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Binder 19
API Recommended Practice 65 — Part 21 Isolating Potential Flow Zones During Well Construction • Isolating Potential Flow Zones During Well Construction API RECOMMENDED PRACTICE 65-PART 2 FIRST EDITION, MAY 2010 C] 0 AMERICAN PETROLEUM INSTITUTE • Isolating Potential Flow Zones During Well Construction Upstream Segment API RECOMMENDED PRACTICE 65—PART 2 FIRST EDITION, MAY 2010 • 0 AMERICAN PETROLEUM INSTITUTE Special Notes API publications necessarily address problems of a general nature. With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed. Neither API nor any of API's employees, subcontractors, consultants, committees, or other assignees make any warranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of the information contained herein, or assume any liability or responsibility for any use, or the results of such use, of any information or process disclosed in this publication. Neither API nor any of API's employees, subcontractors, consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights. API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may conflict. API publications are published to facilitate the broad availability of proven, sound engineering and operating practices. These publications are not intended to obviate the need for applying sound engineering judgment regarding when and where these publications should be utilized. The formulation and publication of API publications is not intended in any way to inhibit anyone from using any other practices. Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard • is solely responsible for complying with all the applicable requirements of that standard. API does not represent, warrant, or guarantee that such products do in fact conform to the applicable API standard. All rights reserved. No part of this work may be reproduced, translated, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L Street, NW, Washington, DC 20005. Copyright © 2010 American Petroleum Institute • Foreword This document was prepared with input from oil and gas operators, drilling contractors, service companies, consultants and regulators. It is based mainly on experiences in the United States outer continental shelf (OCS) and deepwater operating areas of the Gulf of Mexico but may be of utility in other offshore and land operating areas. The content of this document is not all inclusive and not intended to alleviate the need for detailed information found in textbooks, manuals, technical papers, or other documents. The formulation, adoption, and publication of API standards are not intended to inhibit anyone from using any other practices. Shall: As used in a recommended practice, "shall' denotes a minimum requirement in order to conform to the RP. Should: As used in a recommended practice, "should" denotes a recommendation or that which is advised but not required in order to conform to the RP. Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent. This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API standard. Questions concerning the interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 1220 L Street, NW, Washington, DC 20005. Requests for permission to reproduce or translate all or any part 40 of the material published herein should also be addressed to the director. Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A one-time extension of up to two years may be added to this review cycle. Status of the publication can be ascertained from the API Standards Department, telephone (202) 682-8000. A catalog of API publications and materials is published annually by API, 1220 L Street, NW, Washington, DC 20005. Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW, Washington, DC 20005, standards@api.org. 11 • • r� • Contents Page 1 Scope.................................................................................. 1 1.1 Overview................................................................................ 1 1.2 Objectives............................................................................... 1 1.3 Background and Technology Review........................................................1 1.4 Conditions of Applicability ................................................................. 1 1.5 Well Planning and Drilling Plan Considerations ............................................... 2 1.6 Drilling the Well.......................................................................... 2 1.7 Flow Prevention Practices Matrix........................................................... 2 2 Definitions, and Abbreviated Terms......................................................... 3 2.1 Definitions.............................................................................. 3 2.2 Abbreviations...........................................................................12 3 Mechanical Barriers.....................................................................13 3.1 General................................................................................13 3.2 Mechanical Barrier......................................................................14 3.3 Characteristics and Capabilities........................................................... 14 3.4 Subsurface Mechanical Barriers........................................................... 15 3.5 Surface Mechanical Barriers.............................................................. 18 3.6 Alternate Methods.......................................................................19 • 3.7 Operational Considerations............................................................... 20 4 Cementing Practices and Factors Affecting Cementing Success ................................ 23 4.1 Introduction............................................................................ 23 4.2 Hole Geometry .......................................................................... 23 4.3 Drilling Fluid Type....................................................................... 23 4.4 Casing Hardware........................................................................ 24 4.5 Close -tolerance and Other Flow Restriction Considerations ................................... 25 4.6 Engineering Design...................................................................... 26 4.7 Slurry Design and Testing................................................................ 29 4.8 Welibore preparation and conditioning..................................................... 34 4.9 Cement Job Execution................................................................... 37 4.10 Post Cementing Operations............................................................... 40 5 Leak Off Tests.......................................................................... 42 5.1 Introduction............................................................................ 42 5.2 Pressure Integrity Test Procedures......................................................... 43 5.3 Pressure Integrity Test Guidelines......................................................... 44 5.4 LOT Technical References................................................................ 46 6 Post -Cement Job Analysis and Evaluation .................................................. 46 6.1 Material Inventory ....................................................................... 46 6.2 Job Data............................................................................... 46 6.3 Cement Evaluation...................................................................... 46 6.4 Flow Prevention Practices Matrix.......................................................... 47 Annex A (informative) Background and Technology ................................................ 48 Annex B (informative) Well Planning and Drilling Plan Considerations ................................ 68 Annex C (informative) Drilling the Well........................................................... 77 Annex D (informative) Cementing Matrix and Instructions ........................................... 84 • Contents Page Bibliography................................................................................ 94 Figures 1 Decision Tree for WOC to ND Surface Stacks ................................................ 22 A.1 Effect of Curing Pressure on Bond Failure .................................................. 49 A.2 Annular Pressure and Temperature —Well G................................................. 63 A.3 Annular Pressure and Temperature —Well B................................................. 64 A.4 Annular Pressure and Temperature —Well A ................................................. 65 A.5 Mud Densities Measured By Pressure Sensors in Annulus ..................................... 66 A.6 Summary of the Top 11 Fields Pulsed in Canada ............................................. 67 B.1 Casing Shoe Depths with Pore Pressure/Fracture Gradient Graph .............................. 70 Tables A.1 Most frequent Primary and Secondary Barriers that Failed in all Phases (Louisiana + Tx + OCS;1960to 1996)....................................................... 53 A.2 Drilling and Service Well Control Occurrences, 1998/1999..................................... 54 A.3 Drilling and Service Well Control Occurrences, 2003.......................................... 54 A.4 Surface Casing Vent Flows............................................................... 55 A.5 Gas Migration Problems.................................................................. 55 A.6 Packer Isolation Testing and Reporting Program Results ...................................... 55 A.7 Well Status at Time of the Incident . 56 A.8 Blowouts by Well Type................................................................... 57 A.9 Blowouts by Depth Category .............................................................. 57 A.10 1991 API Survey Data on Lost Circulation................................................... 59 • Isolating Potential Flow Zones During Well Construction 1 Scope 1.1 Overview This document contains best practices for zone isolation in wells to prevent annular pressure and/or flow through or past pressure -containment barriers that are installed and verified during well construction. Barriers that seal wellbore and formation pressures or flows may include temporary pressure -containment barriers like hydrostatic head pressure during cement curing and permanent ones such as mechanical seals, shoe formations, and cement. Other well construction (well design, drilling, leak -off tests, etc.) practices that may affect barrier sealing performance are mentioned along with methods to help ensure positive effects or to minimize any negative ones. See Section 2, Definitions, for this scope's applicable parameters including types of wells, well barriers, barrier elements, etc. 1.2 Objectives The objectives of this guideline are two -fold. The first is to help prevent and/or control flows just prior to, during, and after primary cementing operations to install or "set" casing and liner pipe strings in wells. Some of these flows have caused well control incidents that are very serious problems. They threaten the safety of personnel, the environment, and the drilling rigs themselves. The second objective is to help prevent sustained casing pressure tSC P , also a serious industry problem. ^- Another publication, API 90, provides guidelines on managing annular casing pressure (ACP) including SCP, thermal • casing pressure, and operator -imposed pressure. These guidelines include monitoring, diagnostic testing, establishing the maximum allowable wellhead operating pressure (MAWOP), documenting annular casing pressure, and risk assessment methodologies. API 65 has been written to complement the objectives of API 90 and its recommended practices for pressure -containment barriers. Many of the definitions in Section 2 are aligned with those in API 90. 1.3 Background and Technology Review A detailed background and technology review are in Annex A. Historical data, perspectives, studies, statistics, lessons learned, etc. are included. All this information has been written to help explain how some practices work, have become proven or invalidated, or had performance limitations placed upon their application. 1.4 Conditions of Applicability The guidance from this document covers recommendations for pressure -containment barrier (cement, packers, etc.) design and installation and well construction practices that affect the zone isolation process to prevent or mitigate annular fluid flow or pressure. Also covered are practices to identify relevant conditions including those predicted in: 1) a pre -spud hazard assessment, and 2) the actual conditions experienced while the well is being drilled. These practices may also help prevent loss of well control (LWC) incidents and minimize the occurrence of SCP during well construction and production. Pre -spud information gathered from offset well(s) and/or from high resolution seismic surveys can be used to define • the degree of flow potential (low, medium, high) for a particular drilling prospect. Any relevant information should be communicated to the appropriate service provider for incorporation into the design for a particular fluid (mud or cement) and for preparing engineering and operations procedures. • 2 API RECOMMENDED PRACTICE 65-PART 2 If any such conditions are identified, the following should be considered. When possible, the surface location should be relocated outside the area of potential flow to a location with less risk. — When relocation of the wellsite is not possible, the well and drilling plan for the affected section of the wellbore should be modified to mitigate the risk of flow. The next section on well planning details the recommended action steps. As presented earlier herein, the content of this document is not all inclusive and not intended to alleviate the need for detailed information found in textbooks, manuals, technical papers, or other documents. Included are those practices (well design, drilling, completion, etc.) that may positively or negatively affect pressure -containment barrier sealing performance along with methods to enhance the positive effects and to minimize any negative ones. 1.5 Well Planning and Drilling Plan Considerations Annex B includes consideration in well planning and drilling plan determinations, such as evaluation for flow potential, site selection, shallow hazards, deeper hazard contingency planning, well control planning for fluid influxes, planning for lost circulation control, regulatory issues and communications plans, planning the well, pore pressure, fracture gradient, mud weight, casing plan, cementing plan, drilling plan, wellbore hydraulics, wellbore cleaning, barrier design, and contingency planning. These factors should be considered during the planning of the well to enhance the barrier sealing performance. Detailed discussion of these factors is included in Annex B and may be mentioned in other sections. • 1.6 Drilling the Well Annex C gives a general overview of drilling the well and some of the factors that might be considered by the drilling group. Some of those factors may include general practices while drilling, monitoring and maintaining wellbore stability, curing and preventing lost circulation, and planning and operational considerations. There may be other factors to consider such as type and location of the well being drilled. These factors should be considered during the drilling of the well to enhance the barrier sealing performance. Detailed discussion of these factors is included in Annex C and may be mentioned in other sections. 1.7 Flow Prevention Practices Matrix Annex D contains a flow prevention matrix for evaluating the potential impact of elements of the well construction process on the goal of attaining zonal isolation. The sheet should be completed by the operator during the planning of the well to help identify areas needing improvement. Then, as each hole section is drilled and pipe cemented, the parameters relating to that section are scored. At the conclusion of each string, the scores for each parameter should be evaluated again and used as a post job evaluation. The sheet can be printed at each of these stages and placed in the well file. The scores, both by major category and the total can be compiled in a database and, with evaluation of flow occurrences, used for process improvement. 0 ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 2 Definitions, and Abbreviated Terms 2.1 Definitions Many of the definitions in this section are aligned with those in API 90. In addition to those listed below other definitions and abbreviations may be found in oilfield glossaries at websites listed in the Bibliography. [47,48,49,50,51] 2.1.1 ambient pressure Pressure external to the wellhead. In the case of a surface wellhead it would be 0 psig. In the case of a subsea well head, it would be equal to the hydrostatic pressure of seawater at the depth of the subsea wellhead in psig. 2.1.2 annular flow The flow of formation fluids (liquids and/or gases) from the formation into a space or pathway in an annulus within a well. The annular flow may follow various types of flow paths inside the annulus to other points including those at shallower or deeper depths. The flow may exit the annulus and enter another formation(s), or continue along the annular flow path, or both. If the flow reaches the surface of the annulus or the well, it is contained by the relevant barrier elements and creates SCP. In rare cases, the barrier elements may not be present, properly installed, or otherwise fail causing a leak that allows a release of the annular flow from the well. 2.1.3 annular packers and seal rings Mechanical barrier devices with flexible, elastomeric sealing elements that can be run into a well on casing or liners for application as: EL P 1� �MplXcl�= a) annular packers installed in the inner pipe string annulus between the inner -casing or -liner pipe string and the previously installed outer -casing or -liner pipe string or the adjacent subterranean formation in the open hole or borehole, or b) annular seal rings installed on the inner pipe string to seal the microannulus and voids formed between the cement sheath and the inner pipe string. The annular packer type is run into the well with the sealing element having a smaller initial outside diameter that then expands externally across the entire annulus to form a seal against the outer pipe string inner wall or the adjacent formation in the "open hole" or wellbore. The sealing element is either mechanically (elastomer compressed/ deformed by mechanical or hydraulic force) or chemically (e.g. types of rubber/polymer sealing elements that swell in contact with hydrocarbon liquids/gases, saline water, water, etc.) induced to expand. One type of annular seal ring has an elastomeric sealing element that is not designed to expand and may only deform to seal a micro -annulus or void between the cement and the inner pipe string. Another type of annular seal ring may have a chemically induced expandable sealing element that both deforms and increases in volume to seal both a micro -annulus and, to some degree, larger voids or cracks in the cement sheath. 2.1.4 annular pressure buildup APB Pressure generated within a sealed annulus by thermal expansion of trapped wellbore fluids typically during production. May also occur during drilling operations when trapped annular fluids at cool shallow depths are exposed to high temperatures from fluids circulating in deep, hot hole sections. This thermally induced pressure is defined and listed in API 90 as thermal casing pressure. APB is also referred to as annular fluid expansion (AFE). annuli Plural of annulus. A well may contain several annuli formed by multiple casing and liner pipe strings. • 4 API RECOMMENDED PRACTICE 65-PART 2 2.1.6 annulus The space between two concentric objects, such as between the borehole and pipe or between pipe and pipe, where fluid can flow. Pipe may consist of drill collars, drill pipe, casing, liners, or tubing. The annulus designation between the production tubing and production casing is the "A" annulus. Outer annuli between other strings are designated B, C, D, etc. as the pipe sizes increase in diameter. For example, the "B" annulus is between the production casing and the last intermediate casing or the next outer casing. 2.1.7 barrier elements One or several dependent objects preventing formation fluids from flowing unintentionally into another formation or to the surface, i.e. mechanical barriers such as wellheads, polished bore receptacles (PBR), packers, annular seal rings, tubing, or casing, and non -mechanical barriers such as cement, chemical sealants, or competent, impermeable rock formations. The transmission of pressure is prevented by these barriers to flow. See definitions for mechanical barrier, fracture gradient, well barrier, primary and secondary well barriers. 2.1.8 blowout preventer BOP A BOP is large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation. BOPs come in a variety of styles, sizes and pressure ratings. Some can effectively close over an open wellbore, some are designed to seal around tubular components in the well (drill pipe, . casing or tubing) and others are fitted with hardened steel shearing surfaces that can actually cut through drill pipe. Since BOPs are critically important to the safety of the crew, the rig and the wellbore itself, BOPS are inspected, tested and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type and legal requirements. BOP tests vary from daily function testing on critical wells to monthly or less frequent testing on wells thought to have low probability of well control problems. See also definition for diverter. 2.1.9 borehole The 'open hole" intervals in a well which are not cased with pipe. A borehole is a hole interval within a wellbore section that is completely filled with rock formation surfaces also called the rock face that bounds the drilled hole. 2.1.10 bottom hole assembly BHA Bottom hole assembly (BHA) is the collection of the bit, drill collars, stabilizers, reamers, hole openers, MWD/LWD/ PWD, mud motor, directional steering system and other tools at the case of the drill string that serve special purposes associated with drilling. Often the BHA is of an overall larger diameter than the drill string which can serve to swab when the drill string is pulled or surge when the drill string is run in the a well. 2.1.11 cased hole The wellbore intervals in a well that are cased with casing and/or liner pipe. The diameter of these hole sections is the inside diameter of the pipe contained therein. 2.1.12 conductor casing • Provides structural support for the well, wellhead and completion equipment, and often provides hole stability for initial drilling operations. This casing string is typically not designed for pressure containment. In some cases upon completion of the well, it may have a casing head; therefore, it may be capable of containing low annular pressures. This casing is set prior to encountering any hydrocarbons at a depth where the fracture gradient will allow for an • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION increase in mud density and is cemented to the surface or mudline. For subsea and hybrid wells, the low pressure subsea wellhead is normally installed on this casing string. 2.1.13 critical gel strength period This is the time between the development of critical static gel strength (CSGS) and 500 Ibf/100 ft2. 2.1.14 critical static gel strength This is the gel strength of the cement that results in decay of hydrostatic pressure to the point that the pressure is balanced (equals pore pressure) across the potential flowing formation(s). 2.1.15 diagnostic testing Tests or techniques performed to evaluate the existence of annular casing pressure and, in some cases, to attempt to determine the source and flow path of the formation fluids/gas creating the annular casing pressure. Included are pressure bleed down/build up tests, evaluation of fluid types/volumes from bleed down tests, evaluation of real time accessible pressure data, production logs, operational observations, etc. 2.1.16 diverter A device in the flow path at the wellhead that forces fluid to go down a pipe to a pit or tank. 2.1.17 • drilling riser A large -diameter pipe that connects the subsea BOP to a floating surface rig to take mud returns to the surface. Drilling without a riser is normally limited to hole diameters too large for available BOP sizes. A drilling riser is a temporary extension of the wellbore to the surface. 2.1.18 drive/jet pipe Supports unconsolidated deposits and provides hole stability for initial drilling operations. This is normally the first string set and provides no pressure containment. This string can also provide structural support to the well system. See also definition for structural pipe casing strings. 2.1.19 equivalent circulating density ECD ECD is the increase in bottom -hole pressure expressed as an increase in pressure that occurs only when mud or other fluids are being circulated. Because of friction in the annulus as the mud is pumped, bottom -hole pressure is slightly, but significantly, higher than when the mud is not being pumped. 2.1.20 extended leak -off test XLOT This is a leak -off test that is for an extended time frame. The backflow of drilling mud after shut-in is monitored in order to characterize in situ stress values. 2.1.21 external casing packer ECP An ECP is a type of subsurface mechanical barrier also called an annular packer that has inflatable elements mounted on mandrels that are equivalent in strength to the liner or casing string. Also see the definition in this section for annular packers and the description of an ECP in 5.3. C' J API RECOMMENDED PRACTICE 65—PART 2 2.1.22 fixed platform wells Wells completed with a surface wellhead and a surface tree on a fixed platform. All of the casing strings are tied back to the surface wellhead. 2.1.23 formation fluids Fluids present inside the porosity, permeability, fractures, faults, vugs, caverns, or any other spaces of sub -surface formations are called formation fluids whether or not they were naturally formed or injected therein. The physical state of formation fluids may be liquids or gases and include various types such as hydrocarbons, fresh or saline water, carbon dioxide, hydrogen sulfide, etc. Formation fluids may be pressurized, commonly called pore pressure, depending on overburden, injection, or other pressuring mechanisms and may vary in pressure from one formation to the next. 2.1.24 formation integrity test FIT Formation integrity test is similar to a leak -off test (LOT) except that fracture initiation pressure is not exceeded. The objective of a FIT is to test the formation to a predetermined pressure lower than the LOT value and corresponding to the planned maximum well pressure expected in the next hole section. See definition of leak -off tests. 2.1.25 fracture gradient FG • The factor used to determine formation fracturing pressure as a function of well depth in units of ppge — pounds per gallon equivalent mud weight, (kg/m3) or psi/ft (kPa/m). For example, a fracture gradient of 0.7 psi/ft (0.15 kPa/m) in a well with a true vertical depth of 8000 ft (2440 m) would predict a fracturing pressure of 5600 psi (38.6 MPa). 2.1.26 hybrid wells Wells drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing hanger, and a surface "christmas tree" (a set of valves, spools and fittings connected to the top of a well to direct and control the flow of formation fluids from the well). A hybrid well may have either one (single bore production riser) casing string or two (dual bore production riser) casing strings brought up from the subsea wellhead and tied back to the surface equipment. These wells are typically located on floating production platforms such as spars or TLPs. 2.1.27 intermediate casing Casing that is set when geological characteristics or wellbore conditions indicate downhole protection is needed or to prevent lost circulation by casing off weaker formations. Multiple intermediate casing strings can be run in a single well. 2.1.28 leak -off test LOT A leak -off test is an applied pressure measurement to determine the fracture pressure (sometimes called "strength") of the open or exposed formation(s). A LOT or "shoe test' is typically conducted immediately after drilling below a newly installed casing shoe. During the test, the well is shut in and fluid is slowly pumped into the wellbore to gradually increase the pressure on the formation. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a crack -like leak -off path by fracturing the rock. The results • of the leak -off test dictate the maximum pressure or equivalent mud weight that may be applied to the shoe formation during drilling and cementing operations. A safety factor or "kick tolerance" to help ensure safe well control conditions during drilling cementing operations is typically used to determine maximum operating pressures (ECD, surge, etc.) based on leak -off test results and other measurements or calculations. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 2.1.29 liner A casing string that does not extend to the top of the well or to the wellhead. Liners are anchored or suspended from inside the bottom of the previous casing string using a liner hanger. The advantage of a liner is a substantial savings in steel, and therefore capital costs. However, additional tools and risk are involved. The well designer should trade off the additional tools, complexities and risks against the potential capital savings when deciding whether to design for a liner or a casing string that goes all the way to the top of the well (a "long string"). The liner can be fitted with special components so that it can be connected to the surface at a later time. 2.1.30 liner hanger A device used to attach or hang liners from the internal wall of a previously set casing string. Liner hangers are available in a range of sizes and specifications to suit a variety of completion conditions. Conventional liner hangers are "hung" (connected to the last casing) by setting slips that grip against the inner wall of the previously set casing string. Expandable liner hangers are hung by external expansion of the hanger against the inner wall of the previously set casing string. 2.1.31 liner packer A mechanical barrier device typically with flexible, elastomeric sealing elements that can be run into a wellbore with a smaller initial outside diameter that then expands externally to seal the annulus between the liner and the previously installed casing string. Two common types of seal setting mechanisms by elastomeric elements are available: 1) externally expanded elements by mechanical or hydraulic compression/deformation between slips, and • 2) externally expanded elements by expandable liner hangers. Liner packers are either: a) connected to the liner hanger assembly when the liner is run on drill pipe into the well, or b) run separately after the liner is cemented and installed on top of the liner hanger assembly. Liner packers are also called liner top packers as they are installed at or near the top of the liner. 2.1.32 loss of well control LWC Also called a blowout or underground blowout. A LWC incident is an uncontrolled flow of subterranean formation fluids such as natural gases, oil, saline water, etc. and/or well fluids into the atmosphere or into an underground formation. A LWC incident or blowout can occur when formation pressure exceeds the pressure applied to it by a column of fluid such as a drilling fluid, cement slurry, cement spacer fluid, brine completion fluid, or any combination thereof in the column of fluid. 2.1.33 logging while drilling LWD The measurement of formation properties during the drilling of the borehole by logging tools installed in the bottom - hole assembly (BHA). LWD tools measure properties of a formation before drilling fluids invade deeply into and alter a permeable rock properties. LWD works when boreholes are difficult or impossible to measure with conventional wireline tools, especially in highly deviated hole sections of wells. • • 8 API RECOMMENDED PRACTICE 65—PART 2 2.1.34 maximum allowable wellhead operating pressure MAWOP The maximum allowable operating pressure for a particular annulus, measured at the wellhead relative to ambient pressure. It applies to SCP, thermal casing pressure and operator imposed casing pressure. 2.1.35 mechanical barrier A verifiable seal achieved by mechanical means between two casing strings or a casing string and the borehole that isolates all potential flowing zones at or below the wellhead, BOP or diverter. 2.1.36 mudline Mudline as referenced in subsea operations refers to the seafloor. 2.1.37 mudline packoff or packer An upper packer run on the production tubing and set in the production casing below the mudline wellhead to isolate the production riser section from the production casing. These mechanical barrier devices are commonly installed in hybrid wells. 2.1.38 mudline suspension system A casing suspension system that allows a well to be drilled using a surface BOP, surface wellhead and surface drilling • equipment. The mudline suspension equipment provides for individual casing hangers to be installed with each casing string that interconnect with each other at a preset point below the mudline. The mudline suspension casing hangers do not provide a pressure barrier. After the well is drilled and cemented, these casing hangers allow for the removal of the casing string between the casing hanger and the surface wellhead. After these strings are removed, a cap can be placed over each casing string, isolating each casing string and the annular space between it and the previously capped casing string inside, at the casing hanger interface. These wells are tied back prior to the well completion in one of two methods. 1) Individually connecting two or more tieback casing riser strings back to a surface casing head, tubing head/tubing hanger, and christmas tree (see mudline suspension wells). Each string has its own tieback connector which provides a structural and pressure containing connection between the casing strings below the mudline and the tieback casing production riser string from the sea floor up to the surface. 2) Individually connecting two or more tieback casing strings back to a subsea tubing head, again using individual tieback connectors, followed by the installation of a subsea tubing hanger and subsea tree (mudline conversion well or mudline subsea well). 2.1.39 mudline suspension wells A well drilled using a mudline suspension system and a surface BOP. The mudline suspension well may be completed as either a surface well or as a subsea well. 2.1.40 measurement while drilling MWD MWD tools are installed in the BHA near the bit and measure physical properties such as pressure, temperature and borehole trajectory while drilling a borehole. The measurements are made downhole, stored in electronic memory • and later transmitted to or retrieved at the surface. MWD tools that measure formation parameters such as resistivity, porosity, sonic velocity, and gamma ray are called logging -while -drilling (LWD) tools. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 2.1.41 non -aqueous fluid NAF A NAF is a non -aqueous drilling fluid or well circulating fluid, one function of which is to lift cuttings out of the wellbore and to the surface. It also serves to cool the bit and to counteract or over -balance downhole formation pressure that prevents pressure "kicks" or annular flows for formation fluids. Common NAF systems are diesel, mineral oil, or synthetic fluid based invert emulsions, or other non -water based fluids. 2.1.42 nippling down The process of disassembling well -control or pressure -control equipment such as a BOP system on the wellhead. Also called "nipple -down." 2.1.43 nippling up The process of assembling well -control or pressure -control equipment such as a BOP system on the wellhead. Also called "nipple -up." 2.1.44 operator imposed casing pressure Pressure in a casing that is operator imposed for purposes such as casing pressure integrity tests (prior to drilling out the shoe), gas lift, fluid injection, stimulation treatments, thermal insulation, etc. 2.1.45 • overbalance pressure OBP Overbalance pressure is hydrostatic pressure which is greater than the pore pressure of a formation. 2.1.46 polished bore receptacle PBR A PBR provides a honed ID (internal diameter) sealing surface for landing a production tubing seal assembly. A PBR may be used as an expansion joint for tubing movements or as a separation tool to allow removal of the production tubing string while leaving a polished bore and anchor seal assembly set in the packer. A PBR may also be used in lieu of a production packer and is typically run integrally with the production liner. PBR length is determined by analysis of the production tubing movement during various situations such as stimulation, production and well shut-in. 2.1.47 pore pressure PP Pore pressure is the pressure of the fluid inside the pore spaces of a formation. 2.1.48 production casing Casing that is the inner most string of casing in the well. Production fluids enter the casing below the production packer and continue to the surface through the production tubing string. At a minimum, the production casing will be rated for the maximum anticipated pressure that may be encountered from the production zone or applied as operator imposed casing pressure. 2.1.49 primary well barrier 40 First set of barrier elements that prevents flow from a source. • • 10 API RECOMMENDED PRACTICE 65-PART 2 2.1.50 production liner A liner that is the inner most string in which the productive zones are completed. The casing in which the production liner is hung off in is usually referred to as the production casing. 2.1.51 production riser The casing strings rising from the seafloor to the wellhead on fixed platforms or the casing strings attached to the subsea wellhead rising from the seafloor to the surface wellhead on hybrid wells. 2.1.52 production string completion string The production string consists primarily of production tubing, but also includes additional components such as the surface controlled subsurface safety valve (SCSSV), gas lift mandrels, chemical injection and instrument ports, landing nipples, and packer or packer seal assemblies. The production string is run inside the production casing and used to conduct production fluids to the surface. 2.1.53 production tubing Tubing that is run inside the production casing and used to convey produced fluids from the hydrocarbon bearing formation to the surface. Tubing may also be used for injection. In hybrid wells, for example, tubing is used as a conduit for gas for artificial lift below a mudline pack off tubing hanger to isolate the gas lift pressure from the production riser. 2.1.54 pressure while drilling PWD PWD is the common term for a pressure measurement tool installed in the BHA above the drill bit. 2.1.55 rate of penetration ROP ROP is the common term for drilling rate or the speed that the drill bit can drill the rock and deepen the borehole. ROP is usually reported in units of ft/hour or m/hour. 2.1.56 secondary well barrier Second set of barrier elements that prevents flow from a source. 2.1.57 should As used in a standard, "should" denotes a recommendation or that which is advised but not required in order to conform to the standard. 2.1.58 static gel strength SGS A lab tested property representing a fluid's resistance to flow at ultra -low shear rates. See A.14, A.15, and 4.7.8 for more information. 1] ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 11 2.1.59 structural pipe casing strings Casing strings utilized to facilitate the drilling of the well, but are not needed for pressure containment after the well has been drilled. Supports unconsolidated sediments and provides hole stability for initial drilling operations, axial support for casing loads and bending loads from the subsea wellhead. See also definition for drive/jet pipe. 2.1.60 subsea wells Wells completed with a subsea wellhead and a subsea tree, where the subsea wellhead and subsea BOP are located at or near the seafloor. 2.1.61 subsea wellhead A wellhead that is used with a floating drilling rig which uses a subsea BOP stack for well control. The subsea wellhead located at or near the seafloor is usually connected to the surface casing string and all subsequent casing strings are installed, landed, and sealed inside the subsea wellhead's high pressure housing, immediately below the BOP. The well can be completed in one of two methods: 1) using a subsea tree (subsea well); 2) utilizing one or two production risers leading back to a surface casing head, tubing head/tubing hanger, and christmas tree (hybrid well). 2.1.62 surface Surface is the level at which the wellhead is connected to the casing. For subsea operations, surface refers to the 40 seafloor or mudline. For land operations and some offshore wells in shallow water, surface typically is above the land or the water, respectively. 2.1.63 surface casing Casing run inside the conductor casing to protect shallow water zones and weaker formations and may be cemented within the conductor string and is often cemented back to the mudline. The surface wellhead is normally installed on this string for surface wells. 2.1.64 surface well A well completed on the surface with individual casing heads, tubing head, a surface tubing hanger, and a surface christmas tree; all residing at a designated level above the water line on a fixed platform. 2.1.65 sustained casing pressure SCP Pressure in an annulus of casing strings that is: a) measurable at the wellhead of a casing annulus that rebuilds to at least the same pressure level when bled down, b) not due solely to temperature fluctuations, and c) not a pressure that has been imposed by the operator. 2.1.66 thermal casing pressure Pressure generated within a sealed annulus by thermal expansion of trapped wellbore fluids typically during production. May also occur during drilling operations when trapped annular fluids at cool shallow depths are exposed to high temperatures from fluids circulating in deep, hot hole sections. This thermally induced pressure is commonly called annular pressure buildup (APB) or sometimes AFE. 1� u 12 API RECOMMENDED PRACTICE 65-PART 2 2.1.67 well barrier Verifiable envelope of one or several dependent barrier elements preventing fluids or gases from flowing unintentionally from the formation, into another formation or to the surface. A system of barrier elements working together to contain wellbore and/or formation pressures such as a system formed by the casing, production tubing/ packer, annular cement sheath, and competent/impermeable, surrounding rock above and below the producing formation. 2.1.68 wellbore The hole or hole sections in a well or the inside diameter of the wellbore wall (also called the outside diameter of the hole). A wellbore may include both "cased hole" sections and 'open hole" or "borehole" sections of the well. 2.1.69 wellhead The surface termination of a wellbore that incorporates devices for installing the BOP and casing hangers during the well construction phase. Also the system of spools, valves and assorted adapters that provide pressure control of a producing well. The wellhead also incorporates a means of hanging the production tubing and installing the christmas tree and surface flow -control facilities in preparation for the production phase of the well. 2.1.70 well integrity A quality or condition of a well in being structurally sound with competent pressure seals by application of technical, operational and organizational solutions that reduce the risk of uncontrolled release of formation fluids throughout the well life cycle. 2.1.71 weight on bit WOB WOB is often expressed in pounds of force or the total weight of the drill pipe, BHA, etc. on the drill bit during drilling of the borehole though the rock formations. WOB also determines the amount of downward "mechanical' force placed by the bit on top of a cement plug or on a "bridge" or obstruction in the wellbore or borehole. 2.1.72 waiting on cement WOc WOC is often expressed as compressive strength in psi (pound per square in.) and pertains to the time when drilling or completion operations are suspended so that the cementing in a well can be hardened sufficiently. 2.2 Abbreviations ACP annular casing pressure API American Petroleum Institute APB annular pressure buildup BHA bottom hole assembly BHP bottom hole pressure BHST bottom hole static temperature BOP blowout preventer CGS critical gel strength period • CSGS critical static gel strength ECD equivalent circulating density in ppg ECP external casing packer • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION ESD equivalent static density in ppg EMW equivalent mud weight in ppg FG frac gradient in ppg or psi/ft or kPa/m FIT formation integrity test HH hydrostatic head pressure in psi or ppg HPHT high pressure, high temperature (> 10K psi BHP/300° F BHST) Ibm/ga density in pounds mass per gallon LOT leak -off test LCM lost circulation material LT limit tests LWC loss of well control LWD logging while drilling MWD measurement while drilling NAF non -aqueous fluid ND nippling down NU nippling up PBR polished bore receptacle PIT pump -in tests PP pore pressure inside formations ppge pounds per gallon equivalent density psi pounds per square inch PWD pressure while drilling MD measured depth mD millidarcy MMS Minerals Management Service ROP rate of penetration RP Recommended Practice SCP sustained casing pressure SGS static gel strength SPE Society of Petroleum Engineers TOC top of cement TVD true vertical depth WOB weight on bit WOC waiting on cement XLOT extended leak off test 3 Mechanical Barriers 3.1 General 13 Use of downhole mechanical barriers is complementary to properly executed cementing and not a replacement. As with all engineering processes, the applications of subsurface mechanical barriers should be chosen with care. There are situations where such barriers may not be necessary or advisable. It is up to the practitioner to exercise due diligence in understanding the variables involved and make the correct decisions. C , 14 API RECOMMENDED PRACTICE 65—PART 2 3.2 Mechanical Barrier A mechanical barrier is defined in 2.1 as "a verifiable seal achieved by mechanical means between two casing strings or a casing string and the borehole that isolates all potential flowing zones at or below the wellhead, BOP or diverter." This seal inside permanent devices such as wellheads or packers should be installed, energized, tested and/or verified before nippling down the BOP or diverter. The term verified or verifiable refers to those unique circumstances where the seal cannot be tested, such as with an external casing packer (ECP) in an open hole. In this case reliance on surface and downhole indications are necessary to confirm that it is set and in place. 3.3 Characteristics and Capabilities Many annular flows occur while temporary mechanical barriers such as BOPs or diverters are nippled down following cementing operations. These flows result from: — loss of hydrostatic pressure as the unset cement column develops gel strength and supports its own weight; — reduced fluid density in the annulus during cement washout operations; lost circulation during cementing causing: reduced hydrostatic pressure due to shorter fluid columns, lower than planned top of cement columns leaving potential flow zones uncemented; 0 — a combination of these Mechanical barriers can significantly increase the odds of preventing flow past their annular seals after cementing and can also save significant rig time by allowing the operator to move straight into nippling down the BOPs without waiting on cement to cure. This may serve as an incentive for using a subsurface mechanical barrier also called an annular packer. Mechanical barriers are still not intended to replace the primary flow control, a suitably designed and well executed cement job coupled with adequate time for the cement to set properly under actual downhole conditions. Rather, they serve as a secondary barrier to keep the well from flowing while the cement is setting. While mechanical barriers are designed to prevent the flow of annular fluids past the barrier element or seal, setting of the barrier may actually increase the chance of gas entering the cement slurry. This is because setting the barrier isolates all potential flow zones below the barrier from all of the hydrostatic pressure above the barrier. This reduction in overbalance pressure (OBP) on any potential flow zones effectively decreases the CSGS as defined in 4.7.8. The pressure in the annulus therefore drops to the pore pressure of the flow zones at an earlier time after the cement is in place, increasing the window of opportunity for gas to enter the cement slurry. Because of this increased chance of gas entering the cement, it is very important that the slurry placed across potential flow zones is designed with gas migration control properties (see 4.7). Properly designed cement slurries should be used to help prevent the gas from migrating through the annulus once it has entered the cement. If migration is not controlled there is potential for either a cross -flow into a lower pressure zone or the collection of a gas pocket directly below the mechanical barrier. Even if there is a mechanical barrier in place, there is still no guarantee that flow around the outside of the previously set casing shoe(s) to the surface could not occur, but the opportunity for a flow shutoff between strings is much better. Proper evaluation of shoe integrity (see Section 5) can help prevent flow around the outside of previously set casing and liner shoes. A properly designed cement job is extremely important, but there are many factors that can prevent even a well -designed cement job from being properly executed in the field. Examples of these are lost returns, shut downs caused by equipment malfunction during the cementing operations thus preventing uniform and timely placement of cement, getting cement from the wrong tank, etc. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 15 The industry has successfully used liner top packers for many years to eliminate/reduce flow after cementing on deeper strings as well as to reduce squeeze work on liner tops. The liner top packer is a proven product when properly designed, installed, and verified for the specific application. Devices similar to this or that functionally serve the same purpose (mechanical barriers) can be used on shallower strings. Mechanical barriers may keep the well from flowing past the barrier element or seal, which in some cases may allow the cement column to hydrate and set in a static condition enhancing the probability of zonal isolation. Flow may still occur beneath the barrier element or seal. A mechanical barrier may prevent flow up between casing strings to the BOP making the job safer. If washing out between strings is required for a given well plan and the probability exists that fluids will flow (i.e. the well contains zones that may flow behind the pipe), then a subsurface mechanical barrier may be recommended since the effectiveness of a BOP is negated by the small -diameter tubulars run inside the BOP or diverter to wash out the cement. If a subsurface mechanical barrier cannot be used to control flows in this situation, then the annulus should not be washed out until the cement has set sufficiently to prevent a flow (which may preclude washing out at all). 3.4 Subsurface Mechanical Barriers 3.4.1 General Some mechanical barriers can be run downhole to isolate an annulus. These subsurface mechanical barriers are also called annular packers with several different types available. The positioning of these devices depends on both purpose and design. To avoid exposing potential trapped pressure, the subsurface mechanical barrier should be placed deep enough below the mudline so that it remains in place when the well is plugged and abandoned. When there is a potential or known flow zone not separated by a mechanical barrier from a potential or a known loss zone, there is the risk of interzonal flow. Other options that may enhance the cement barrier below the mechanical barrier for consideration are as follows. - a) seal rings; b) drill smooth, gauge boreholes for placement locations; c) place across competent formations; d) top of liner squeeze when lost circulation occurs; e) tack and squeeze when necessary [see 3.6 2)J; f) delay setting seals to allow cement to set properly; g) optimize all primary cementing parameters; - h) eliminate all voids that can trap fluids; i) minimize equivalent circulating density's (ECD's) job placement by preventing flow restrictions; j) reverse cement if necessary; k) design cements to enhance the mechanical properties if needed. • The following sections (3.4.2 through 3.4.10) are examples of items/tools that can be used as subsurface mechanical barriers. 16 API RECOMMENDED PRACTICE 65—PART 2 3.4.2 Inflatable ECPs Inflatable ECPs are packers that have inflatable elements mounted on mandrels that are equivalent in strength to the liner or casing string. The advantages of ECPs include the ability to run through reduced Us and seal in larger ID sections of casing or open hole. If the ECP is set directly above the problem zone in open hole then all casings above the zone are protected if the packer seals effectively. Some open holes may not be suitable for sealing by an ECP such as holes with geologic hazards (fractures, faults, unconsolidated, etc.) or with drilling induced large washouts and keyseats. Sealing elements or elastomers can be designed for specific applications. The wellhead and BOP stack should be selected with a minimum ID sufficient to accommodate the ECP. After bumping the plug, differential pressure capability of a liquid filled ECP is a function of element design and the ID of the casing or open hole in which it is set. If the element is inflated with cement then the differential pressure capability is limited only by the casing or open -hole strength. Cement inflation is recommended for many applications. Optimal results are usually obtained when expanding cement (cement capable of post -set expansion without access to external water) is used. [11[21 In all applications planning is critical, and analysis of temperature and pressure changes during the life of the well should be included in the ECP design. 3.4.3 External Mechanical Casing (EMC) Packers Another mechanical device is the external mechanical casing (EMC) packer and collar combination. Basically a sub is run in the previous casing string with a load shoulder built into it which is fluted for fluid by-pass. This load shoulder will reduce the ID of the casing string which will alter normal bit selection when drilling out of this outer casing string. The EMC packer is run externally on the inner casing string. The inner string should be planned to set off bottom (i.e. there should be a rat hole below the casing string to allow the inner string to be set in tension). Mudline suspension cannot be used with this system because the casing should be landed off bottom, as well. At the completion of the cement job, weight is slacked off energizing the EMC pack -off on the inner string and creating a seal between the strings. The pack -off should then be tested. This device is not applicable for all casing configurations. It should be sized for the diameters of the tubulars involved and the differential pressure across the annular area. 3.4.4 Hydraulic -set External Casing Packers Hydraulic -set external casing packers can be used in situations in which pressure can be applied to the casing string to set the packer. This generally implies bumping the plug that follows the cement slurry; however, pressure can be applied through alternate means. This type packer does not require a load shoulder or other setting device. Applied pressure activates hydraulic cylinders within the tool to generate pack -off forces. At the completion of the cement job the packer is energized creating a seal between casing strings that can be verified by application of surface pressure on the annulus. This type device is applicable to all casing applications anywhere on the casing string within the 'overlap" (casing/ casing annulus) area and does not require that casing be set off bottom. Packers are available with or without slips but should be sized for the diameters of the tubulars involved and differential pressure across the annular area. 3.4.5 Mudline Casing Suspension Systems (MCSS) Mudline casing suspension systems (MCSS) can also be used if cement removal in the annulus to a point below the mudline is desired. This equipment allows for removal of cement without disabling the BOP. Removal of the cement • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 17 can be accomplished by opening the wash ports provided at the disconnect point and circulating the cement from the annulus. This is not a strictly a mechanical barrier, however. MCSS provide a means to support the casing string weight at or near the mudline and also provide a means to disconnect the casing strings above that point for the purpose of temporary abandonment. The suspension/disconnect point is often positioned sufficiently below the mudline to accommodate any requirement of the appropriate regulatory agency to remove the casing below the mudline for permanent abandonment. To ensure the ability to disconnect the casing for temporary abandonment, cement should be washed out of the casing annulus above the disconnect point. If water is used, the hydrostatic pressure above the MCSS could be reduced enough to permit the well to flow, and a shut-in would be required. Consideration should be given to the use of heavier fluids to wash out. Shut-in would also be required prior to nippling down to prevent flow if there is no mechanical barrier used in conjunction with the MCSS. 3.4.6 Liner Packers Liner packers, also called liner top packers, are generally used at greater depths where liners are commonly employed. They are typically run in the well with the liner and often set immediately after cementing. They provide a way to shut off the annulus between the liner and the casing above the liner and may prevent flow past the packer after cementing. They have also allowed the operator to safely proceed with operations without having to waiting on cement (WOC) since they are pressure tested immediately after they are set. While these packers have a proven history of preventing flow after cementing and SCP, in some cases the recommendations listed in 3.4.1, 2nd paragraph, should be followed. A new version is the expandable liner hanger that has elastomer pack off elements installed on the outside of the liner hanger joint. After liner cementing operations are complete, these devices hang the liner and pack -off the annulus without the use of slips by expanding the hanger joint and sealing elements enough to contact grip the inner wall of the outside casing inside the liner lap. This both suspends or supports the weight of the liner pipe string and forms a reliable, annular seal between the casing and the liner. See 3.4.10 for more information. 3.4.7 Chemically -set Annular Packers Chemically set annular packers are mechanical barrier devices with flexible, expandable-elastomeric sealing elements that can be run into a well on casing or liners for applications to completely seal the annulus between the casing or liner pipe string and the previously installed casing or liner pipe string or "open hole" formation(s). This type of annular packer is run into the well with the sealing element having a smaller initial outside diameter that then expands externally across the entire annulus to form a seal against the outer pipe string's inner wall or the adjacent formation in the "open hole" or borehole. The sealing element is chemically induced to expand, e.g. various types of rubber/polymer sealing elements that swell in contact with hydrocarbon liquids/gases, saline water, water, etc. 3.4.8 Annular Seal Rings Annular seal rings are mechanical barrier devices with flexible, elastomeric sealing elements that can be run into a well on casing or liners for applications to seal the microannulus and voids formed between the cement sheath and the inner pipe string. The sealing element has an outside diameter designed to seal the size of a microannulus and should not excessively restrict flow during the hole conditioning and cementing process. The sealing element is not designed to expand and may only deform to seal a micro -annulus or void between the cement sheath and the inner pipe string. 3.4.9 Expanding Annular Seal Rings Expanding annular seal rings are mechanical barrier devices with flexible, expandable-elastomeric sealing elements that can be run into a well on casing or liners for application to seal the microannulus and voids formed between the • 18 API RECOMMENDED PRACTICE 65—PART 2 cement sheath and the inner pipe string. This type of annular seal ring is run into the well with the sealing element having a smaller initial outside diameter that then expands externally and deforms against the cement sheath and/or into voids therein to seal a microannulus and, to some degree, adjacent voids or cracks in the cement sheath. The sealing element is not designed to move set cement and expand against the outer pipe string or the formation. However, it may deform/expand into and fill small cracks in the cement sheath that extend between the inner and outer pipe strings or formation(s). This penetration is limited by the original volume of the sealing element and the designed expansion thereof. 3.4.10 Seal Rings for Expandable Tubulars (ET) Seal rings are commonly installed at or near the top of both expandable tubular (ET) liners or expandable liner hangers to provide a mechanical barrier while preserving the maximum interior diameter of the liner. These extrudable rings are installed on the outside surface of the liner and are expanded along with the tubular liner forming a seal against the interior surface of the host pipe. The elastomers and fillers from which these rings are composed are selected based on elasticity, plasticity and heat resistance based on the predicted temperature at their setting depth. When an ET liner is installed below a host pipe, the liner is placed on the bottom of the hole and cement is (optionally) circulated around the pipe. Then a cone or other device expands the pipe to a larger diameter. The expansion process also shortens the pipe. If the pipe is expanded from bottom to top, it cannot be hung conventionally from the host pipe without inducing significant tension in the string as the ET is expanded. By placing the seal rings at or near the top of the liner, they are in the last portion of the string to be expanded. The friction between the pipe strings and the cured cement hold the liner in place. The now extruded seal rings provide a mechanical barrier to flow in the small annulus between the two pipe strings. This friction fit allows the drill pipe or other carrier string to be detached from the expanded liner. A liner can be suspended from an expandable liner hanger set in the host pipe. The mechanical functions of the hanger result in a reduced ID, which cannot be tolerated in many designs. Expanding the liner hanger, and possibly the ET below it, preserves the ID of the system and permits easy recovery of the running string. Clearly, these liner hangers and the pipe below them must be expanded from the top down if the hanger cannot move during the ET expansion process. Seal rings on the exterior of the liner hanger body perform the same function as those on the exterior of the ET body providing the mechanical barrier between the host pipe and the expandable liner hanger. Designs of these tools vary depending on function and purpose. Some have only the elastomer rings to provide the seal relying on the metal -to -metal friction to hold the hanger in place. Others include slip segments and sharp ridges on either side of the seal ring that are pushed into the host pipe to stabilize the ring and prevent damage while running the hanger and extrusion of the elastomer outside the seal area. A potential problem that must be overcome when using these expandable seal rings involves electronic resistance welded (ERW) casing for the host pipe. The small ridge left on the interior of the casing must be removed in the sealing area. This provides a smooth surface for proper extrusion of the seal ring during the expansion process. If the ridge remains, a small void may exist between the seal ring exterior and the casing on either side of the ridge, which will compromise the barrier. This problem does not exist if seamless pipe is used in the host pipe in the seal area. 3.5 Surface Mechanical Barriers Other items can be installed at or near the surface that can serve as mechanical barriers. These devices also seal the annulus, but in the wellhead area rather than downhole. Examples of these are as follows. 1) Some wellhead systems provide several casing suspension and sealing positions in a single wellhead housing. This allows the landing and sealing of more than one casing string without the need to remove the BOP after cementing to add an additional wellhead. These wellheads can also serve as a mechanical device to seal the annulus and allow the BOP to be nippled down without waiting on cement for long time periods. ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 19 They can be installed on top of the drive pipe and used to seal the annulus between the surface casing or conductor casing. Since the inner casing is landed off bottom with only the drive pipe to support it, the possibility exists for the entire assembly to fall due to the weight of the surface or conductor casing. In this case, drive pipe should be driven to refusal or into a competent formation. Alternatively, the wellhead can also be installed on the conductor casing and rest on the drive pipe for additional support. These wellheads may have a retractable load shoulder on which to land the casing via a fluted hanger, but there are other types that do not require retractable load shoulders. The pipe is cemented, and then the hanger and packoff are landed through the BOP sealing the annulus. The BOP could be safely nippled down after this seal is tested. All strings should be landed off bottom, which precludes the use of a MCSS. 2) Conventional wellhead equipment that does not provide several casing suspension and sealing positions in a single wellhead housing requires that the BOP be disconnected and lifted to install the slip and seal assembly around the casing just cemented. Unfortunately, in most cases, this requires several hours during which the cement column begins to develop static gel strength, reducing its ability to transmit hydrostatic pressure to the formation and allowing the possibility of an influx of liquid or gas from the formation. This is why minimization and control of cement static gel strength (SGS) development is a very important practice (see 4.7.8). There is specialized equipment that can facilitate completing this operation. An example is a "quick connector' This device does not require studs and nuts (the removal and re -installation of which require significant time). With such a device, if the well begins to flow, the BOP can be lowered and the connection to the wellhead restored quickly. A conventional studs and bolts nipple down would be difficult to execute in the time required. In the event the well began flowing prior to setting the slip and seal assembly, the stabbing and securing of studs would also be a high risk operation. • 3.6 Alternate Methods Several other mechanical methods and materials can be employed to allow operations to continue without annular flow while WOC. The following are examples of these. 1) Liners, including drilling and scab liners, with a mechanical seal at the top may be run and cemented inside previous casing to save the cost of a wellhead and to save NU/ND (nipple up/nipple down) time associated with the BOP and diverter. In many cases this liner is simply set on bottom inside the drive pipe after cementing in place to seal the annulus. To be effective, cement should come up between the liner and the host string of casing and should be verified with a test. If cement or a seal is not verified and a kick is taken on the following hole section, then the host shoe would see the pressure and could ultimately break down and flow to surface on the outside of the drive pipe (host string). One liner system incorporates a shoulder and seal area welded into the drive pipe that accepts the seals and hanger for the liner. The liner would be set off bottom. Typically, this system requires the liner hanger to be above the landing shoulder during cementing to allow fluid bypass. After cementing, the liner is lowered and the seal engaged. This system can also be provided such that the liner can be set on the landing shoulder allowing for cementing operations and setting of the seal without having to lower the liner hanger. When setting the liner in the drive pipe, the operator does not have any ("A" section) wellhead containment at the surface. Essentially the scab liner is an extension or deepening of the drive pipe. This deepening could extend the drive pipe down into more consolidated surface formations with the ability to flow very low pressure gas. This could lead to uncontained low pressure gas flow from the drive pipe which normally has a base plate attached which would block any reasonable safe access to the wellbore. If the operator has to run a liner in the drive pipe then the operator should weld up the drive pipe surface outlet (donut shape insert). The operator should also install a pressure gauge on one side (top of the donut insert) and an access nipple on the other to bleed low pressure gas to a safe location using a high-pressured and hydrocarbon -rated hose or hard piping. This nipple should also be used to inject heavy mud after bleeding any gas. This arrangement gives the operator a safer method to handle any low pressure gas escaping from the drive pipe x scab liner. • 20 API RECOMMENDED PRACTICE 65-PART 2 The annulus between the liner and the host casing should be tested to 150 psi, as is common practice, above the frac gradient at the host casing or drive pipe shoe to verify the seal is effective before drilling ahead. 2) Certain circumstances are not conducive to conventional liner cementing practices. Lost circulation, long liners, or simply no need for a full cement column may allow for a small volume of cement to be placed at the shoe, followed by injecting a volume of slurry down the liner top annulus. This is commonly referred to as a `Tack and Squeeze" method. Slurries used in this application should meet normal liner cementing guidelines for placement and set time. This liner cementing method may optionally use a liner top packer. Special adaptations may be required of the liner running tools to carry out this operation, including but not limited to running a retrievable service packer in the drill string above the liner running tools. All pertinent operating procedures of those specific tools should be followed and modified as needed to perform the combined operation of pumping the primary cement slurry to the shoe followed by the liner top cementing operation. 3) Other remedial procedures may be applied such as top jobs, etc. See more information on these options in 4.10. 3.7 Operational Considerations 3.7.1 Waiting Time Guidelines Prior to Nippling Down Regulators require that if the operator plans to nipple down the diverter or BOP stack during the WOC time period, the operator should determine when it will be "safe" to do so. Determination of the "safe" WOC time should take into account several factors including whether or not a hydrocarbon zone is exposed in the wellbore or if there is the possibility that one is exposed (if it is unknown).There may be other downhole conditions that could modify the guideline. It is extremely important that any plan for nippling down the BOP stack be modified toward a conservative approach to avoid loss of well control or endangerment to personnel or equipment. Some factors that could affect the plan include: — substantial loss of returns while pumping cement; — delays in getting cement in place, such as pump interruptions that could lead to poor mud removal and poor cement consistency; — premature returns of cement to surface; — high gas units in the drilling mud prior to cementing. In these cases, confidence in the cement job would decrease, and waiting on cement for a longer time before nippling down would be prudent. 3.7.2 Special Operational Considerations The following are special operational considerations. — Operators and contractors should do a complete risk assessment prior to utilizing foam cement, and will make sure that the results of this assessment are communicated in the cementing plan. Operators and contractors should not run tubing in the annulus between the casing and the diverter, or BOP, prior to completion of cementing operations and determining that the well has no potential for flow. The operator should verify that hydrostatic pressure calculations are performed to ensure sufficient hydrostatic • pressure throughout the well prior to washing out to the mud line suspension hanger (MLSH). • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 21 3.7.3 WOC Decision Tree Procedures 3.7.3.1 General The WOC procedures for surface stacks presented below are an excellent tool for making a decision on when and under what conditions it would be safe to ND the BOP or diverter system. These procedures are based on the best information and technology available and the user should update them as new technology and information become available. The importance of proactive contingency planning where the possibility of flows after cementing exists cannot be overemphasized. This planning should include all parties involved in doing the work and specifically should include the operator, drilling contractor, cement contractor and the contractor providing the mechanical barrier, if applicable. In all cases, the operator and contractor should have a plan to minimize the time from the start of ND the BOP to securing the exposed annulus with slip and seals. No other activities should take precedence over securing this annulus. Waiting time can be reduced or avoided if the operator has a mechanical barrier in place and tested to verify a pressure seal prior to ND the BOP (see NOTE). NOTE Nippling down when waiting -on -cement is allowed if the wellhead or casing annulus has been sealed off and tested. Advanced planning is a must between the operator, drilling contractor, cementing company, and mechanical barrier company if that option is selected. 3.7.3.2 Procedures: Step 1 Determine whether potential flow zones exist in the open hole section of the wellbore. If it is known that no hydrocarbon zones exist in the open hole, or that the zones identified have low permeability with little to no flow potential, it is not necessary to wait -on -cement after completion of the cement job. In this case, go to Step 4 (see 3.7.3.5). If the presence of potential flow zones cannot be determined or if hydrocarbons have been found, go to Step 2 (see 3.7.3.3). 3.7.3.3 Procedures: Step 2 Once the cement job has been completed, the WOC time period prior to nippling down BOPs is determined as follows. In all cases below, the WOC time assumes that the cement job was properly designed and executed as planned. That it, there is no lost circulation, the cement was mixed as designed within a reasonable time, no pump failures causing delays in placement, etc. The determinations for the WOC time period are as follows. — 1 st Level Decision. If there is a mechanical barrier or a special wellhead in place and tested to contain a potential flow, go to Step 4 (see 3.7.3.5). — 2nd Level or Primary Cementing Decision (use if the 50-psi compressive strength data is known). Wait for the cement to reach 50-psi compressive strength at the temperature of the potential flow zone as determined by laboratory tests (See NOTE 1 and NOTE 2). Go to Step 3 (see 3.7.3.4). NOTE 1 The primary decision information should be requested from the cementing company long before the cement job commences, preferably at the pre -spud meeting or before. It may be possible for the operator to modify the slurry mixture and have it re -tested to minimize the WOC time. • NOTE 2 Studies done by some of the cementing companies have shown that once the cement reaches 500 Ibf/100 sq. ft gel strength, gas can no longer migrate through the cement slurry. As part of the "conservative approach" in 3.7.1, this 50-psi compressive strength value used in the WOC decision tree far exceeds this minimum gel strength. The reported compressive • 22 API RECOMMENDED PRACTICE 65—PART 2 strength development times may be in significant error if the temperature used for testing differs significantly from the actual temperature in the potential flow zone. Testing at a temperature higher than the actual temperature will reduce the time to develop compressive strength. This situation may lead to nippling down early and should be questioned. — 3rd Level or Secondary Decision (use if compressive strength data is unknown). If the criteria for 1 st Level or 2nd Level decisions cannot be met and if unable to confirm NO hydrocarbon zones in the open hole section of the wellbore, the operator should establish an appropriate course of action with the regulator or permitting authority (see NOTE 3). Go to Step 3 (see 3.7.3.4). NOTE 3 The best course of action is to obtain the proper cementing information and KNOW when the cement slurry reaches the appropriate WOC value rather than resorting to a rule of thumb measurement. The operator should reconfirm the course of action with the regulator or permitting authority if any conditions discussed in 3.7.1 occur. 3.7.3.4 Procedures: Step 3 Once the WOC time in hours is determined by lab tests for the specific cement slurry, the operator should wait on the cement to set for that amount of time prior to removing or disabling the BOP equipment, or have a mechanical barrier seal in place and verified on that annulus. 3.7.3.5 Procedures: Step 4 After making sure the annulus is full, proceed according to the operator's planned procedures (may include nippling down the stack). • 3.7.4 WOC Decision Tree Figure 1 is an image of a WOC Decision Tree. Start Are there hydrocarbon bearing zones Proceed according to operator's in the open hole? No plan (see steps 1 to 4) Yes or don't know Is potential flow contained by a Proceed according to operator's "mechanical barrier" between strings plan (see steps 1 to 4) or special wellhead? Yes No Is 50 compressive strength data WOC time to develop available for this 50 psi, then proceed cement? Yes according to operator's plan (see steps 1 to 4) No or don't know WOC as agreed with the regulator, then proceed according to • agreed plan (see steps 1 to 4) Figure 1—Decision Tree for WOC to ND Surface Stacks • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 23 4 Cementing Practices and Factors Affecting Cementing Success 4.1 Introduction This section summarizes many of the key drilling issues that affect the quality of a primary cementing operation. This section is not exhaustive, nor does it provide the reader with a comprehensive set of detailed recommendations for well construction. The intent is to highlight the salient aspects that should be considered and summarize the interrelationship between drilling operations and cementing success. All topics discussed are covered in detail in various API, ISO, and other industry publications. 4.2 Hole Geometry Hole geometry affects many aspects of the cementing operation. Among these are centralizer/centralization requirements, casing running conditions and ability to move pipe, mud removal, and ECD in ppg while circulating and cementing. The relationship between hole size and casing size should, from a cementing perspective, always strive to achieve the best balance between displacement efficiency and equivalent circulating density. Past studies have indicated that 0.5 in. to 0.75 in. are generally recommended minimum annular clearances in a uniformly concentric annulus (i.e. minimum hole size should be 1 in. to 1.5 in. greater than pipe OD). However, modern fluid systems and fluid mechanics modeling allow more precise matching between hole geometry and fluid properties. Maximum recommended clearances between casing and the wellbore should be determined by desired minimum annular velocity and fluid friction pressure profiles versus available hydraulic horsepower and/or maximum pump • rates as determined by surface equipment and open hole fracture gradients. Minimum annular clearance is determined by drilling and completion objectives, how much annular coverage is desired, formation limitations (fracture versus pore pressure), and logging considerations. Cement sheaths less than 0.5 in. thick are difficult to evaluate with cement evaluation logging tools. Drilling and fluid management practices should strive to minimize hole washout via proper bit hydraulics and shale inhibition. Weight on bit and rate of penetration should be controlled to minimize unintentional doglegs and/or trajectory changes. Under -reaming practices and bi-centered bit use should concentrate on minimizing double -helix hole geometries that interfere with mud removal and pipe movement during cementing operations. The directional survey, complete with azimuth, should be included in calculations for centralization, torque and drag, and displacement modeling, especially when wellbore spiraling cannot be avoided. 4.3 Drilling Fluid Type 4.3.1 Drilling Fluid Selection Drilling fluid (mud) selection and maintenance play a key role in cementing success. Drilling fluid performance affects hole condition (washouts), mud filter cake thickness and gel strength (measured as described in API RP 136-1 or API RP 136-2), mud mobility, fluid and formation compatibility, and bonding of cement to formation. Drilling fluid selection is generally dictated by anticipated formation types and drilling conditions, penetration rate and differential sticking and environmental, disposal and logistical considerations. While drilling fluid selection does impact subsequent cementing operations, that impact is not often considered in the selection process. Unfortunately, the ideal drilling fluid is not necessarily that best suited for cementing operations. Drilling fluid performance is controlled by many factors. Low -gravity or active solids should be effectively controlled, • and adequate shale inhibition should be provided for aqueous mud systems. HTHP filter cakes should exhibit thin, low permeability characteristics. Gel strength and low shear rheology at HTHP conditions should be low and non - progressive, but not at the sacrifice of drill cuttings transport or barite support. • 24 API RECOMMENDED PRACTICE 65-PART 2 Achieving good cementing success through effective mud displacement requires proper planning. Computer modeling of cement placement or mud displacement requires careful evaluation of fluid properties and placement processes. 4.3.2 Rheology Rheological properties of the drilling fluid should be obtained at anticipated wellbore temperatures and pressures for proper displacement modeling. The rheological properties of some drilling fluids, synthetic -based fluids in particular, can vary widely with changes in pressure and/or temperature. Drilling fluid samples representative of the drilling fluid at the time of cementing should be tested with cementing fluids for rheological and chemical compatibility. Laboratory - prepared samples of drilling fluids are generally not sufficiently representative of actual well fluid for this evaluation. Samples collected at the rig as near to casing set point as logistics permit should be used for these evaluations. In the case of nonaqueous drilling fluids, the ability of the cementing spacers and/or preflushes to fully water -wet pipe and wellbore should be evaluated as detailed in API RP 10B-2 and ISO 10426-2. 4.3.3 Hydrate Prevention Gas hydrates are simple crystalline chemical compounds composed of water molecules surrounding a single free- floating natural gas molecule. The crystal is arranged in a compressed latticework, appearing very similar to ice formed from water. Unlike ice, however, hydrates can form at temperatures above the freezing point of water when system pressures are elevated. Hydrate formation has led to plugging of wellbores, flowlines, and wellhead and well control equipment, and has jeopardized operators's abilities to maintain positive control of pressures in the wellbore. The prevention of gas hydrates is thus a critical concern wherever they are encountered. • Pre-emptive measures should be taken to insure that hydrates do not form and do not become a safety/well control problem. The key to hydrate prevention is to inhibit the formation of hydrates through the proper selection and design of the drilling and completion fluids. Low dosage gas hydrate inhibitors (anti-agglomerants) and a combination of anti- agglomerants/kinetic polymeric inhibitors have been successfully tested for the prevention of hydrate formation. Other methods including the use of solvents such as methanol, maintaining the proper drilling fluid salinity and the use of non -aqueous base fluids can also reduce the likelihood of hydrate formation. Computer models that predict the formation of hydrates under various conditions are available to the operator from a variety of sources. 4.4 Casing Hardware 4.4.1 General Casing hardware and auxiliary downhole equipment may be used to enhance the cementing operation. This includes centralizers, float equipment, stage collars, external casing packers, liner hangers and liner top packers and expandable casing (mechanical barriers are discussed in Section 3). 4.4.2 Centralizers Centralization of the casing is of paramount importance to successful zonal isolation. Computer simulators are highly recommended for determining the best centralization design for a given application (see discussion under 4.6). Casing centralizers exist in many models and designs and are generally categorized as either rigid, solid or bow - spring models. Auxiliary functionality such as flow diversion and mechanical friction -reduction is also available. Custom-built centralizers are available for either slimhole or extremely large annular clearances.). See discussion of installation under 4.8.3 and 4.8.3.2. Also, see API Spec 10D, Specifications for Casing Centralizers, and API RP 10D-2/ISO 10427-2 Petroleum and natural gas industries —Equipment for well cementing —Part 2: Centralizer 0 placement and stop collar testing • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 25 4.4.3 Float Equipment Float equipment is used to prevent the cement from flowing back into the casing when pumping is stopped and/or pressure released. Test procedures for various classes of float equipment and associated mechanical components are provided in API RP 10F/ISO 10427-3, Recommended Practice for Performance Testing of Cementing Float Equipment. Float equipment choice should always be matched to anticipated bottom hole temperatures and the pressure differentials expected at the end of the cement job. Specialized float equipment including auto -fill, side -ported, and custom -profiled is also available to address the functionalities of surge -reduction and collapse protection, improved hole cleaning, and ease of running casing, respectively. Float collars are also available that lock and hold the wiper plugs to prevent rotation during drillout. A float collar and a float shoe can be used together to provide redundant flow - back control as well as a receptacle for contaminated cement slurry. Some lost -circulation materials (LCM) in the drilling fluid and/or cementing fluids may preclude or hamper the use of certain float equipment valve designs. 4.4.4 Plugs Casing and liner wiper plugs, whether conventional surface release or subsea release provide the function of mechanically separating cementing fluids from the drilling fluid, wiping the ID of the tubulars, and providing a positive indication of the end of displacement. Wiper plugs should be matched to the anticipated bottom hole temperatures, pressures, depths and mud type (aqueous or nonaqueous). Not all wiper plugs and associated operating systems (releasing darts) are compatible with all types and manufactures of float equipment and/or stage tools, liner hanger tools, and liner top packers. Tapered ID casing strings may require customized wiper plug systems. Wiper plugs and associated operating systems should be matched to the casing size and weight and all other casing hardware components to ensure compatibility. 4.4.5 Cementing Plug Containers and Heads Cementing plug containers and head assemblies provide the means by which conventional casing wiper plugs can be launched from the surface without significant interruption of pumping operations. Each type of cementing head has its own specific capabilities in terms of pressure ratings, mechanical operation, load -carrying capacity, and auxiliary capabilities such as allowing rotation or remote operation. These characteristics are published by the head's manufacturer. Not all casing wiper plugs are compatible with every model of cementing head and float equipment. Cementing heads and plug sets should always be checked for compatibility. Plug containers equipped with remotely - operated plug releasing mechanisms reduce risk to personnel and may minimize shut -down time. Cementing heads should always be in good working order and be pressure -tested on a regular basis. Various components that should be examined and function tested on a regular basis are the cap, coupler, seals, 0-rings, extensions, threads, lift swivels, hoist rings, manifolds, along with any associated swages. Magnetic particle inspection should be performed on a periodic basis, or if a component is suspect. Type -certification is available from the service provider in many instances. A type -certified plug container is one that has fully traceable components with material mechanical properties verified by laboratory tests. In addition, a certification of design strength approval for the design may be issued by Lloyd's Register or other certification body. 4.5 Close -tolerance and Other Flow Restriction Considerations Close tolerances may restrict the flow of drilling and cementing fluids during well circulation and cause lost circulation. Close tolerances are often encountered in pipe -to -pipe annuli, liner tops, expandable casings, and between the inner diameter of outer tubulars and some tools such as liner hangers, liner top packers, tieback sleeves/receptacles, stage tools, ECP's, and expandable tubulars. Conventional types of liner hangers also have reduced flow cross -sectional • area called "bypass area" from the flow restrictions formed by the unset slips protruding from the hanger body. The bypass area is further reduced after these slips are set against the inner casing wall to "hang" or connect to and suspend the liner from the casing. Close mechanical tolerances should be examined for mechanical (drift) compatibility with all components involved in the cementing operations including wiper plugs and associated • 26 API RECOMMENDED PRACTICE 65—PART 2 operating components. Minimum and average cross -sectional area and length of the restricted flow path should be examined for compatibility with drilling and cementing fluid properties and/or material components such as LCM. Circulating pressure calculations should include any flow restrictions associated with close tolerances, particularly those of significant length such as liner laps and tieback sleeves. 4.6 Engineering Design 4.6.1 General Cementing objectives determine the cement designs to be used, extent of cement coverage with each, and performance requirements of each. Performance requirements include gas control, static gel strength transition time, fluid loss, free fluid, thickening time, and compressive strength. Tensile strength and elasticity may also be considerations. 4.6.2 Zonal Coverage Determination It is important to evaluate which zone(s) have potential for flow in order to plan the cement job to achieve suitable zonal isolation. Ideally, such zones should be covered with cement slurries designed to prevent flow after cementing, and the cement placement mechanics should be designed to maximize mud removal. Zones left uncemented may not flow in the short term if pore pressure is balanced by mud hydrostatic head. However, phenomena such as barite sag and mud dehydration may lead to onset and long-term SCP. Cement top selection is influenced by the location of the problem zones, regulatory requirements and pore pressure/ fracture gradient consideration. Higher density tail slurries may be more easily designed to be "gas tight' (gas • controlling) than some lower density lead cements. However, some types of gas controlling cement slurries may be more easily designed based on solids to liquid content than density. If the potential problem zone is to be covered by tail cement, the tail slurry should have a shorter critical gel strength period (CGSP) than the lead slurry so gel strength development in the lead slurry does not reduce the hydrostatic head exerted on the zone before the tail slurry goes through the CGSP. 4.6.3 Pore Pressure/Frac Gradient Accurate knowledge of pore pressure and fracture gradient profiles is necessary for successful primary cementing and helps design jobs that prevent lost circulation and annular flows. Pore pressure is a crucial piece of information needed to assess flow potential. The pore pressure and fracture gradient profiles are two of many input values used in computer simulation programs used to evaluate static and dynamic well security. 4.6.4 Temperature Temperature has the single greatest influence on cement slurry performance. Accurate estimates of cementing temperatures (both static and circulating) are essential to the success of the cement job. These may be available through thermal modeling and or measurement in offset wells. For many wells, API temperature schedules provide adequate estimates of circulating temperatures. However, these schedules are based on data collected in wells in shallow water with little deviation (see API TR 10TR3, Temperatures for API Cement Operating Thickening Time Tests, 1993 Report from the API Task Group on Cementing Temperature Schedules). The API schedules should not be used for wells that vary greatly from these conditions (e.g. deepwater offshore wells). For such "non-standard" wells, circulating temperature information can be obtained using temperature recording devices that are made up in the drillstring or dropped into the drillstring and run on clean-up trips. These devices measure the maximum temperature encountered as well as changes in temperature as the well is circulated. The • measurements are taken with a geometry (drillpipe) different than what will be present in the well during the actual cement job (casing) so the measured values may deviate from actual temperatures during cementing. Also, because the devices are run after the hole section has been drilled, little time is available for slurry modifications. Finally, temperature measurements are more commonly considered in production hole sections than in shallower strings, • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 27 although the effects of temperature on cement performance are just as important in the shallower strings, especially if there is potential for flow. Computer -based thermal modeling programs may be used to develop cementing temperatures. Such programs require input information such as static temperature, formation and well fluid thermal characteristics, estimated job volumes and planned pump rates. Temperature information may be obtained from measurement while drilling (MWD) tools as the hole is drilled. Temperatures from MWD devices tend to be higher than those derived from models or sensors used on cleanup trips. Several factors account for this including an elevated mud suction temperature while drilling compared to initial slurry temperature while cementing. Some bottomhole assemblies and formation types have been demonstrated to give highly elevated MWD readings. In summary, there are many sources of temperature information. All temperature information should be considered. Rather than a single, "correct" answer, the engineer will likely be presented with a range of likely temperature values. The slurry design should perform acceptably over the anticipated range. 4.6.5 Mud removal design 4.6.5.1 Design Proper slurry design is only part of a successful cement job. The other part involves efficiently removing the drilling fluid from the well and replacing it with cement slurry. Computer based placement simulators allow the engineer to tailor the cement job to a particular well's conditions rather than relying on "rules of thumb." The following are factors • to include in planning for efficient mud removal. 4.6.5.2 Pump Rate Higher pump rates introduce more energy into the system allowing more efficient removal of gelled drilling fluid. However, tight annular clearances in some wellbore configurations limit how fast the job can be pumped without causing lost returns. Depending on the differentials between fluid rheology and density of the displacing and displaced fluids, and the degree of centralization and hole angle, specific pump rates may promote uneven flow between the narrow and wide sides of the annulus. Fluid simulation modeling should be performed to determine the best annular velocity, given the parameters of the wellbore. 4.6.5.3 Fluid Type The types of fluids used during drilling and cementing operations affect the cement job. A drilling fluid conducive to wellbore stability benefits the cement job by producing a uniform, near -gauge hole with minimal hole washouts. After the hole is drilled, the drilling fluid should be displaced with cement to achieve zonal isolation. In addition, all fluids used in the cementing operation should be compatible. Compatible fluids are fluids that are "capable of forming a mixture that does not undergo undesirable chemical and/or physical reactions." Mixtures which become viscous when mixed are difficult to displace efficiently and may cause lost circulation due to excessive friction pressure. If non -aqueous fluids (NAFs) are used, a spacer containing surfactants that water -wet downhole surfaces will be necessary (compatibility and wettability test procedures are found in API RP 106-2). 4.6.5.4 Rheology and Density As a general statement, barring chemical interactions and turbulent dilution effects, mud removal is more efficient • when the displacing fluid displays a higher frictional pressure drop and is heavier than the fluid being displaced. Various guidelines have been used to decide how to design the density and Theological hierarchy in the displacement design. Narrow pore pressure/fracture gradient windows in some wells may limit application of density/rheology hierarchies. 0 28 API RECOMMENDED PRACTICE 65-PART 2 4.6.5.5 Mud Compressibility Depending on the temperature and pressure, the density of compressible fluids may increase significantly at well pressures, affecting fluid rheologies and wellbore pressures. Commonly available viscometers used at the rig take measurements at atmospheric pressure and thus will not show the effects of compressibility. For more accurate cement computer displacement simulations, mud samples should be tested at a laboratory under higher, more realistic confining pressure. 4.6.5.6 Cement Preflush (Wash) and Spacer Design The purpose of preflushes and spacers is to aid in bulk mud removal by avoiding incompatible mixtures of the cement slurry and drilling fluid. When NAFs are used, these fluids remove the oily mud film and water -wet the downhole surfaces. Procedures for testing spacer compatibility are found in API RP 1013-2. Some computer simulators may help optimize the volume of spacers to be pumped for mud removal. 4.6.5.7 Pipe Movement One of the best aids to achieving effective mud removal is pipe movement; either rotation or reciprocation. 4.6.5.8 Centralization If casing is not centralized, it may lay near or against the borehole wall. Mud, washes, spacers and cement slurry flow most easily on the wide, less restricted side of the annulus. It is difficult, if not impossible, to displace mud efficiently from the narrow side of the annulus if the casing is poorly centralized. This results in bypassed mud channels and • inability to achieve zonal isolation. Centralization is necessary to improve flow all around the pipe and aid in mud removal. Computer software is available to design centralizer placement to achieve optimum standoff for mud removal. The effectiveness of centralization is dependent on a number of factors, including the hole size and deviation, casing size and weight, fluid densities, and centralizer placement and properties. Centralizer properties to be considered in calculating the standoff include centralizer type (e.g. rigid, solid or bow spring), minimum and maximum OD and restoring force. The actual standoff performance properties provided by the manufacturer should be used in these calculations. Caliper logs (preferably giving two diameters) and directional surveys are necessary to correctly calculate standoff. Starting and running force properties should also be considered in selecting centralizers. 4.6.5.9 Computer Simulations As is true with many areas of study, computers have greatly improved the design process for well cementing. Using computer simulators, the engineer can tailor the cementing process to account for an individual well's unique conditions. It is no longer necessary to rely on general "rules of thumb." Each cementing service company has its own simulator. Simulators are also available from third party vendors. These simulators vary in their capabilities and strengths. Typical capabilities include: — U-tube calculations to predict whether the cement job can be performed within the pore pressure/frac gradient window, considering ECD; — displacement efficiency; is— foam cementing calculations; • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 29 — circulating and post cementing temperature profiles; — swab and surge pressures. As with any computer program, the quality of a cementing simulator's output depends on the degree to which the input variables are known. It is not likely that a simulator can provide a single "right" answer. However, by bracketing variables, the engineer can gain insight that will assist in achieving zonal isolation. The information entered into the computer simulation should be as accurate as possible. This information should include actual mud, spacer, and slurry rheologies, actual caliper log information (if available), actual survey data (if possible), actual tubular configuration, actual fracture and pore pressures, and actual hardware configuration. 4.7 Slurry Design and Testing 4.7.1 General Cement should be placed in the wellbore and provide good contact with the casing and borehole wall, prevent the formation of channels within the cement and prevent the invasion and propagation of fluid through the cement as it sets, and provide mechanical support. The cement should maintain its integrity throughout the life of the well. Cement properties necessary to meet these objectives include: — rheological properties that aid mud displacement, • — hydrostatic pressure control, fluid loss control as appropriate, free fluid and sedimentation control, control of gel strength development (see 4.7.8), — resistance to invasion of gas or fluid, — rapid set and adequate short term and ultimate strength, long-term sealing (bonding/mechanical resilience). Test methods for determining the performance of cement are described in API RP 1OB-2 (ISO 10426-2), API RP 1OB-3 (ISO 10426-3), API RP 1OB-4 (ISO 10426-4), and API RP 1OB-6 (ISO 10426-5). These methods should be modified, as closely as possible, to the conditions to which the cement will be exposed during placement across the potential flowing zones requiring isolation. Temperature/ pressure schedules should be devised for conditioning and curing the cement for these tests. The use of thermal wellbore simulators is discussed above. 4.7.2 Lead and Tail Cement Lead and tail cements are routinely placed in the annulus during primary casing cementing. Lead cements are cement slurries that are designed with lower densities by extending the cement with low cost components, either water or readily available low density materials. In addition to the cost consideration, low density lead cements are used to lower the hydrostatic pressures to avoid or minimize losses of the cement to the formations. Tail cements are typically mixed without extending components and thus have a higher density and are more costly than most lead 40 slurries. 1r I J 30 API RECOMMENDED PRACTICE 65—PART 2 The design of the cement which will cover the potential flowing formations should be considered carefully. Lead cements, although not normally "designed" to cover formations which might flow, can be designed to control flows. Doing so may require special formulations. Slurries are frequently designed with special properties and/or additives to control the flow. Lead slurries which are placed across "non -productive" formations having the potential to flow should be designed using the same criteria as slurries placed across the hydrocarbon bearing zones. 4.7.3 Density Density plays a key role in the design of cement slurries. In cases with potential for flow, there are two primary considerations for selecting the density: preventing losses to the formation and preventing flow from permeable formations. This implies the density should fall between that necessary to provide enough hydrostatic pressure to control flow from the permeable formations and that which will fracture the weak formations causing lost or partially lost circulation (see previous discussion of pore pressure/frac gradient under engineering design). Note that the density of the slurry does not itself need to fall between the pore and fracturing pressure, but the effective density (that is the ECD) must fall between those pressures. Other considerations related to the density of the slurry are the performance related to strength development and slurry stability. Meeting the requirements of strength and slurry stability may make the use of special slurry formulations necessary to achieve the recommended density. The density under placement conditions (temperature and pressure) should be considered in the design. Some slurries are compressed by pressure while others have components which are deformed by pressure. Either of these can lead to higher densities after placement downhole than the density at which the slurry was mixed at surface. • 4.7.4 Thickening Time The thickening time is the time that a cement slurry is judged to be pumpable (API RP 106-2). Testing should be under conditions simulating those downhole during placement. Slurries should be designed for the specific set of conditions found in the well and for the designed pumping schedule (rates) to be employed during the cementing operation. Wellbore temperature simulators are used to model anticipated well temperatures while cementing and can be used to develop schedules for conducting tests. The use of excessive safety factors in thickening time design should be avoided. Excessive safety factors can cause delayed setting, long periods of gelation and increased likelihood of solids segregation. These factors may present a higher potential for flow from the formation before the cement has adequate strength to prevent it. Thickening times should be designed so that slurries set from the bottom to the top of the well. Gel strength development progression should also be from bottom to top. 4.7.5 Fluid Loss Control of fluid loss plays a key role in preventing flow. Loss of fluid from the slurry after cement placement is a contributing factor in the loss of the overbalance pressure controlling flow. The rate of fluid loss is dependent on the overbalance pressure, the permeability of the formation, the condition of the mud cake (including its permeability), and the fluid loss characteristics of the cement. There are numerous fluid loss additives available, such as synthetic and natural polymers, copolymers, latex, and blends thereof. Fluid loss testing should be done after conditioning the slurry at conditions similar to those in the wellbore. Fluid loss test temperature should be that which the slurry will experience across the potentially flowing zones. It is not possible to make a precise rule about the recommended level of fluid loss; it depends on many factors, but lower fluid loss is always better where there is potential for flow. ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 31 4.7.6 Slurry Stability, Sedimentation, and Free Fluid Stability of the slurry is an important property in preventing annular flow. Free fluid and sedimentation may occur simultaneously or one may occur without the other. Free fluid can result in a channel or a void in the cement into and through which formation fluid or gas can easily flow. It may also result in a severely underbalanced condition (through the water channel) initiating the flow. Control of free fluid is imperative in situations where there is the potential for flow. Not only is the presence of a channel and the resulting underbalanced condition critical, but the condition of the remaining slurry is key as well. When water is lost from the slurry (by free fluid separation), the solids concentration is increased. This can result in uncontrolled gelation, changing other properties of the cement (such as ability to transmit hydrostatic pressure). Additionally, sedimentation (which results in concentration of solid particles in lower sections and reduced concentrations in upper sections of the well) should be controlled. The properties of the slurry will be changed by sedimentation, leading to greater gelation where the solids are concentrated and low strength and high permeability where they are reduced. Slurries should be conditioned at temperatures encountered during placement and free fluid and sedimentation tests conducted at the temperatures to be encountered while static in the annulus. 4.7.7 Rheology Rheology affects the displacement of fluids and friction pressure generated during placement. The design of the fluids should take these parameters into account. Slurry stability is dependent on the rheology. Gel strength development may also be affected by components of the cement which are used to control rheology. All of these effects should be considered together. Rheology is tested at atmospheric pressure at temperatures up to 190 °F (88 °C). Fluids may be conditioned at elevated temperatures greater than 190 °F (88 °C) in HPHT consistometers and then cooled to 190 °F (88 °C) before checking rheology values. To avoid burns, care should be taken when such testing is conducted at high temperatures. Care should be taken to select the proper rheological model when simulating fluids to be pumped on a cement job. 4.7.8 Gel Strength Gel strength affects the ability of slurries to suspend their solids in a static condition. It also contributes to decay of hydrostatic pressure as the gelled fluid interacts with the casing and the borehole wall. Thus, the gel strength of cement slurries should be designed to be adequate to support the solids and yet, not be excessive. One method to evaluate gel strength development is to measure the "critical gel strength period." There are two concerns in the control of gel strength for annular flow control; low gel strength until just before setting and rapid gel strength development to 500 Ibf/100 ft2. The CSGS is the time between the development of CSGS and 500 Ibf/100 ft2. Studies by earlier researchers referred to a different time period for SGS development, i.e. one started at 100 Ibf/ft2 and ended at the same 500 Ibf/ft2. The CSGS method is now preferred. The CSGS is the gel strength of the cement that results in decay of hydrostatic pressure to the point that the pressure • is balanced (equals pore pressure) across the potential flowing formation(s). API RECOMMENDED PRACTICE 65-PART 2 The CSGS is computed by: CSGS = (0BP)(300)(L/Dell) where OBP is the overbalance pressure (psi); 300 is the conversion factor; is the length of the cement column (ft); /here is the effective diameter (in.) = DOH - D,; D, is the diameter of the casing (in.); Do,-, is the diameter of the open hole (in.). Gel strength is intimately related to the hydration of the cement, the chemical reaction between the powdered cement and water to produce a solid matrix. These reactions and the gel strength depend on temperature, the chemical and physical nature of the cement being used and materials added to the cement to control its properties (e.g. thickening time, fluid loss, etc.). Gel strength can be controlled by the use of additives. Additives for controlling other properties of the cement should be selected with control of gel strength in mind. Standard techniques for measuring gel strength of other fluids often give poor results with cement. API 1013-6/ISO 10426-6 contains standard tests for gel strength determination. Service companies have developed methods for determining gel strength at temperature and pressure to simulate wellbore conditions. The gel strength can be measured using a device that allows measurement under pseudostatic conditions [at a rotation of 0.2°/minute (or at shear rate of 10-3 sec-1) or less] on an apparatus designed to make this measurement under simulated downhole conditions. The gel strength may also be determined using special rheometers designed to measure gel strength, pressure drop measurements or ultrasonic correlations. The critical gel strength period should be minimized to the extent possible. A maximum critical gel strength period of 45 minutes (measured at the temperature of the potentially flowing zone) is commonly accepted. 4.7.9 Compressive and Tensile Strength There are two WOC times of interest: WOC to nipple down and WOC to drill out. For nippling down the BOP, the strength development profile of the cement should indicate initial set of the slurry (see additional discussion of WOC in 4.10.2 and 3.7.4). The development of strength is also a primary consideration in continued operations such as drillout. Early workl31 has shown that 8 psi tensile strength, or about 100 psi compressive strength (compressive strength is about 8 to 12 times tensile strength for most cements), is adequate to support the casing. WOC time before drillout is normally the time that laboratory testing has shown it takes the cement around the casing shoe to develop 500 psi compressive strength. There has been a tendency in the past to maximize compressive strength. For the short term, this may seem appropriate, but for later well operation, high strength may be contrary to good well integrity (see discussion in • 3.7.10). • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 33 4.7.10 Compatibility Any fluid being displaced should be compatible with the fluid displacing it. Fluid compatibility has been discussed previously in 4.6.5.3. Compatibility between cement slurries is not normally a problem, but with certain types of slurries it can be. This is especially true for latex -containing slurries in contact with extended slurries. Compatibility between slurries should be tested to ensure that rheological behavior, thickening time, fluid loss and slurry stability are not compromised. Procedures described in API RP 10B-2, Section 16 can be adapted to test cement slurries for which there is concern about compatibility between the slurries. 4.7.11 Mechanical Parameters Besides compressive and tensile strength, Young's modulus and Poisson's ratio play a key role in the integrity of the cement during the operation of the well. Stresses placed on the cement by changing pressures (including pressure testing, hydraulic fracturing, etc.) and temperatures in the well or changes due to reservoir pressure can cause a microannulus to form between the cement and the casing or radial cracking of the cement sheath, or both. These conditions can lead to fluid leakage through the cement sheath, sometimes to surface. Pressure at the surface caused by such leaks is commonly known as sustained casing pressure. Wellbore simulation software can be used to determine the proper combination of strength and flexibility for a specific well within its operation conditions. There are no standardized tests for determining Young's Modulus and Poisson's ratio for cement under wellbore • conditions. Tests have been adapted from other disciplines for testing oil and gas well cement formulations, but the results derived from these different test protocols can vary widely for a given cement formulation. 4.7.12 Expansion/Shrinkage Cement may shrink under certain conditions encountered in the wellbore. Such shrinkage may lead to loss of seal, leading to leakage through or around the cement. Expansive agents may be employed to counteract the effects of this shrinkage, however, excessive expansion can also be detrimental to cement integrity. Expansion against an incompetent or "soft" formation can lead to microannulli at the cement/casing interface or the formation of radial cracks in the cement sheath. Test methods for determination of shrinkage or expansion of well cement are found in API RP 1OB-5 (ISO 10426-5, Petroleum and natural gas industries —Cements and materials for well cementing —Part 5: Test methods for determination of shrinkage and expansion of well cement formulations at atmospheric pressure). 4.7.13 Cement Slurry Techniques for Controlling Annular Flow A number of slurry design philosophies have been shown to be effective in controlling annular flow. These include compressible slurries, such as foam cement and cement with gas liberating materials, latex of certain types, systems containing microsilica, slurries with surfactants or polymer dispersions, very low fluid loss slurries, and static gel strength controlled slurries. Certain of these require special laboratory testing techniques. Some of these slurries and techniques are proprietary and service company design criteria should be met for their use. LJ • 34 API RECOMMENDED PRACTICE 65-PART 2 4.8 Wellbore preparation and conditioning 4.8.1 General Every effort should be made to minimize the time between completion of the hole interval and cementing when flow hazards exist. With the cementing process in mind, the fluids used to drill should be designed for ease of removal. Conditions should be maintained to minimize changes in hole conditions which would lead to difficulty achieving a seal during the cementing operation. 4.8.2 Well Preparation 4.8.2.1 General Well preparation, particularly circulating and conditioning fluids in the wellbore, is essential for successful cementing. Many primary cementing failures are the result of fluids that are difficult to displace and/or of inadequate wellbore conditioning. Particular attention should be placed on low fluid loss (thin, tough filter cake) and rheological properties that provide low, flat gel strengths. Even when good well preparation is planned, contingencies in the cementing operation should be provided in case well conditions prevent the planned well conditioning program from being performed. Well preparation includes: — determining hole size to confirm the recommended volume of cement slurry; • — adjusting drilling fluid rheological properties to aid in its removal during cementing; ensuring the well is dead; — curing losses; — conditioning of fluids prior to cementing to ensure that gel strength is broken, that cuttings and gas are removed and that the well is cooled for cementing. The pre -cementing considerations that are included in this summary are based on sound cementing best practices that are known to enhance the probability of success. Primary cement job failures are predominately due to a breakdown in the "displacement process" which leads to channeling of the cement through the drilling fluid. These guidelines, when applied in conjunction with a simulation software program will enhance the displacement process and improve the probability of successful primary cementing. Simulation software can be used to help determine the optimum displacement parameters and safe operating ECD. 4.8.2.2 Caliper the Hole Size A hole caliper log is a recommended prerequisite for any primary cementing job design to confirm the volume of cement slurry required to fill the annulus to the designed top of cement in the annulus (TOC). The actual hole size should also be known to allow proper calculations of friction pressure, both during the cementing operation and when running casing. It is also necessary to calculate the centralizer requirements and from centralizer calculations, to calculate flow regimes and rates recommended for effective mud removal. The hole caliper should be of sufficient quality to make the necessary calculations. When conditions prohibit the use of a hole caliper log, a fluid caliper may provide a gross measurement to the hole's circulating volume (see 4.8.4). The use of hole caliper logs and fluid • calipers have shown that excess cement volumes are often needed compared to the volume based on the hole size being equal to the drill bit outside diameter. For example, in many areas 100 % or more excess cement is needed to cement surface casing. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 35 4.8.2.3 Lost Circulation Control Before cementing casing or liner, lost -circulation should be eliminated or significantly reduced. This is best done prior to cementing. If this is not possible, or if losses are anticipated during the primary cementing job, there are several options. The first is to maintain the downhole circulating pressures below the pressure at which losses occur by reducing the density of the cement slurry, minimizing the height of the cement column and limiting friction pressure during the cementing operation. Other options are to pump a plugging material as a spacer in front of the cement slurry and add lost circulation materials to the cement slurry itself. These techniques are usually used in combination. 4.8.2.4 Wiper Trip —Conditioning the Drilling Fluid After logging and prior to cementing, a wiper trip should be made to help stabilize the wellbore and remove any remaining cuttings. The mud should be conditioned in preparation for cementing. The condition of the drilling fluid is one of the most important variables in achieving good displacement during a cement job. Regaining and maintaining good mobility of the mud is key. Flow rate should be sufficient to ensure flow of all mud, including in washouts (see also the discussion of flow rate in 4.8.4). Drilling fluids with low gel strength, low rheology and low fluid loss are more easily displaced. Pockets of gelled fluid, which commonly exist following drilling, make displacement difficult and should be broken up. Conditioning should include adjusting the mud properties, as measured under downhole pressure and temperature conditions, to those which will be favorable for mud removal during cementing. To condition the drilling fluid in preparation for a cement job, the following should be performed. • a) Modify the flow properties of the drilling fluid to optimize drilling fluid mobility and removal of drill cuttings. Yield point (YP) and gel strengths should be maintained as low as possible without causing settling of solids from the fluid. These variables should be evaluated for the specific well conditions. In deviated wellbores a higher -viscosity drilling fluid may be recommended to help prevent solids from settling on the low side of the wellbore. The presence of large drill cuttings may also necessitate higher viscosity fluids. The higher -viscosity fluid needs to be optimized based on wellbore conditions and inclination. After removal of cuttings, consideration should be given to lowering viscosity of the drilling fluid to aid in its removal. b) The gel strength profile of the drilling fluid should be determined at bottom hole temperature and pressure as per procedures recommended in the following publications: 1) API RP 1313-1, for water base drilling fluids. The ISO equivalent is ISO 10414-1 2) API RP 1313-2, for oil base drilling fluids. The ISO equivalent is ISO 10414-2. Gel strength should be as low as possible with a `flat' or non -progressive gel strength profile. The API standard time periods for measuring gel strength are at 10 seconds and 10 minutes. Longer time periods are allowed by the API procedures such as measurements at 30 minutes or longer. For the purpose of conditioning the drilling fluid during a wiper trip, a minimum of three measurements (10 second, 10 and 30 minutes) are recommended to plot a gel strength profile showing whether or not a "flat' profile exists. In addition, a longer term gel strength test may be run at the bottom hole temperature and pressure. This testing would typically be performed during the planning stage. During conditioning just prior to the job, readings taken at 10 seconds, 10 minutes, and 30 minutes determined on location are typically sufficient. c) Maintain filtrate loss control. Filtrate loss into a permeable zone enhances the creation of a filter cake. A high fluid loss creates a thick or high viscosity, drilling fluid layer immediately adjacent to the formation wall that is difficult to is Fluid prior to or during cementing. The fluid loss recommended is dependent on the hole section being drilled. Fluid loss control should be maintained while conditioning the hole and running casing and cementing. Note that a thick, gelled filter cake deposited while drilling using high fluid loss mud cannot be repaired by later lowering the fluid loss of the mud. r1 J 36 API RECOMMENDED PRACTICE 65-PART 2 4.8.2.5 Rathole Rathole beneath the casing shoe can lead to contamination of cement during placement, or mud can swap with the cement after placement. These can result in poor strength development, pockets of mud, or a wet shoe. Rathole length should be minimized or filled with cement or some other type barrier materials to prevent this. 4.8.3 Running Casing 4.8.3.1 Surge Mitigation Tools/Procedures The surge effect of running casing can result in fracturing, wellbore damage and possibly well control loss. When casing is run into the hole, a piston effect is caused by the friction pressure of the gelled mud flowing past the casing as it is run. The mud flow rate (and the friction pressure) is proportional to the casing running speed. Running casing with a closed end (normal float equipment) causes the mud to flow faster up the annulus, whereas when run open- ended or with automatic fill float equipment, the fluid velocity (and friction pressure) in the annulus is reduced since part of the mud fills the casing. As the well has been static since the wiper trip, the mud will be gelled. This also increases the surge pressure. With sensitive or weak formations, the surge pressure should be minimized. Surge pressures can be reduced by reducing running speed and by the use of floats that allow mud to flow into the casing while it is run. Surge pressures can also be reduced by lowering the rheology and gel strength of the drilling fluid prior to running casing. Surge effects can also be reduced by pausing while running casing to circulate mud, removing the gelled mud from • the well and replacing it with well -conditioned mud from the pits. Casing running speeds should be evaluated prior to the job by using surge calculation software to determine maximum running speeds without damaging the formation or losing mud. Surge simulation software can also show the effects of lowering mud viscosity or gel strength and may be used for input to the fluid engineer for use in conditioning the mud during the wiper trip. 4.8.3.2 Centralizer Program Centralizing the casing across the intervals to be isolated helps optimize drilling fluid displacement. In poorly centralized casing, cement will follow the path of least resistance; as a result, the cement flows on the wide side of the annulus, leaving drilling fluid in the narrow side. In a deviated wellbore, standoff is even more critical to prevent a solids bed from accumulating on the low side of the annulus. The recommended standoff should be determined from computer modeling of mud removal and will vary with well conditions (see discussion in 4.6). Centralizers should be run according to an engineering design for optimum cementing results. Centralizers can be installed such that they are allowed to slide between casing collars or clamped in place via either limit clamps or set screws on the centralizer itself. Such holding devices should be of adequate construction to withstand the forces of running casing and pipe movement during cementing. Centralizers installed on flush joint casing should be equipped with stationary holding devices. The practice of clamping centralizers in place with set screws that do not allow them to rotate should be used with caution as it limits the movement of the casing if it were to become stuck. The preferred method of installation of bow string centralizers is so that the centralizer is pulled into the hole, rather than pushed. An example of "pulling" a centralizer is when it is placed around the collar; an example of "pushing" a centralizer is when it is allowed to travel freely on a joint of casing. • 4.8.4 Conditioning After Casing is Landed When the casing is on bottom and before cementing, circulating the drilling fluid will break its gel strength, decrease its viscosity and increase its mobility. The drilling fluid should be conditioned until equilibrium is achieved. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 37 The volume of the circulatable hole can be estimated by using a fluid caliper. Good fluid returns at the surface do not reliably indicate the mobility of fluid in the annular space. A fluid caliper is a small volume of fluid which is easily identifiable when it appears on the shale shaker or returns to the pits after circulation. Knowing the time between injection and recovery, and the pump rate, the volume of fluid which is flowing in the well can be calculated. A fluid caliper pumped through the well in a full hole or "trip" volume circulation helps perform several functions: — measure the openhole circulating volume by subtracting casing capacity and pipe -in -pipe annular volume from the trip volume, — measure hole cleaning performance (gelled mud/cake/cuttings removal) of various methods/materials mentioned below, — validate cement volumes predicted by wireline caliper logs. Hole cleaning methods include higher circulating rates, pipe movement, and the use of high/low viscosity "sweep" pills to remove any partially dehydrated "gelled" mud, wall cake, and cuttings that can impair mud displacement during cementing. More information can be found in the literature (see Annex E for papers SIDE 18617141 and 29470151). At a minimum, the hole should be conditioned for cementing by circulating 1.5 annular volumes or one casing volume, whichever is greater. Once the drilling fluid is well -conditioned (i.e. drilling fluid properties going in equal to properties at the flowline outlet), • it should continue to be circulated until spacer and cementing fluids are pumped. Shutdown time between conditioning and cementing should be minimized by installing the cement head and pressure testing lines before conditioning the well. The time to drop the plug should be minimized by proper planning. It is best to land casing close to the floor to allow easy access to pins and valves on the cementing head necessary to drop the plug (and to minimize hazards). 4.9 Cement Job Execution 4.9.1 Bulk Plant QAIQC Accurate cement blends are extremely important to the success of any cement job. Care should be taken to ensure that the field blend matches the blend tested in the laboratory. Cement blends should be blended in accordance with the written procedures established by the service company providing the cement blend. In addition, the personnel blending and/or loading the cement should be properly trained and certified bulk plant operators. The cement blenders and all associated equipment should be regularly maintained and inspected to ensure there are no leaking valves or other equipment malfunction that could cause improper additive introduction, erroneous cement concentrations, or contamination. Equipment to be inspected includes check valves, pressure relief valves, interior blender surfaces, additive hoppers, and aeration devices. Appropriate actions, should be taken to ensure that no contamination is possible whenever blends are loaded. Bulk plant scales should be accurate and in proper working order. These scales should be part of a regularly scheduled calibration program. Copies of the calibration certification should be retained at the bulk plant. A certified calibration technician should perform all calibrations. • Bulk plants should be equipped with proper sampling devices to ensure that multiple samples are taken throughout each blend. The sampling device should be located in an area on the discharge line that ensures that excess moisture cannot enter the sample containers. r 1 38 API RECOMMENDED PRACTICE 65—PART 2 Certain cement blends require specific loading best practices. Service company -specific best practices should be used as appropriate. 4.9.2 Cement and Additive Lot Numbers The service company providing the cement and/or cement blend should follow all established, documented company procedures to ensure that all received neat cement is within acceptable specifications upon arrival at the bulk plant. In addition, the lot numbers of all additives used should be documented for each cement blend. This information should be contained in the paperwork associated with the particular job for which the blend is loaded. A minimum of two samples of at least one gallon each of neat cement or blend should be documented, labeled, and retained. One of these samples should be retained at the bulk plant and the other sent to the lab for verification testing (if recommended). If verification testing is recommended, testing should be conducted with representative samples of location water. 4.9.3 Transportation and Storage of Cementing Materials All cement blends should be stored in properly maintained bulk storage tanks. This includes physical inspection of the pads and interior surfaces of the tanks prior to loading/bulk transfer. Tanks should be physically swept out after a cement blend is stored in the tank. This will ensure that no contamination is present in the storage tank(s). In addition, discharge, fill, inspection port, and vent valves should be checked to determine that no valves are malfunctioning. Cement volumes to be loaded should take into account any bulk transfer losses that may occur. This is particularly important in an offshore environment where losses in the bulk tanks of a boat and in transfer to the rig may be significant. Boat tanks should also be physically inspected and, if necessary, swept out prior to loading. • 4.9.4 Mixing and Pumping Slurry density fluctuations can have adverse effects on slurry properties including: reduced or extended thickening times, free fluid, retarded compressive strength development, extended slurry transition time, and reduced fluid loss control. Additionally, density fluctuations can result in increased ECD, fracturing of weak formations, and the potential loss of well control. The cement spacer(s) and slurries should be mixed at the planned densities. Batch mixing should be employed if mixing on -the -fly methods are not adequate. All attempts should be made to ensure that the slurry density is within the acceptable range. Computer -aided density control systems are recommended to ensure that the slurry is mixed at the proper density. 4.9.5 Implementing the Job Design and Adhering to Planned Procedures The pumping of the cement job should be according to planned rates and volumes. The planned rates should be obtained from the output of a computer simulation (see 3.6.4.8). The computer simulation should determine maximum pumping rates allowable and mud removal efficiency at planned pumping rates. Recommended hardware configuration data includes centralizer data, hanger systems bypass area, liner packer dimensional data, etc. Having accurate input data ensures that the simulation output will be accurate and feasible. Deviating from planned job design can result in poor zonal isolation due to formation fracturing or mud channeling. Due to this, it is recommended that discussions be held with all pertinent parties prior to a deviation from planned procedure. 4.9.6 Pipe Movement • Pipe reciprocation and rotation can assist in effective mud removal. Pipe movement assists in mud removal by altering the flow path of the mud, spacer(s), and cement slurry. Pipe movement can also help to break the gel strengths of mud that may otherwise be bypassed by the spacer and slurry. Reciprocation should be done slowly to ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 39 ensure that surge pressures are minimized and losses are not induced due to fracturing of formations. Computer surge programs can supply the maximum reciprocation rate during a cement job. Proper equipment should be utilized anytime pipe movement is planned. When reciprocating, ensure that enough treating iron has been installed from the rig floor to the cementing plug container. Pipe rotation necessitates the use of equipment designed to rotate without creating stress on the plug container and treating iron. 4.9.7 Data Acquisition All pertinent job data should be monitored and recorded by computerized data acquisition equipment. The data to be recorded should include density of all fluids pumped, rate at which they were pumped, and surface treating pressure. Pressure and rate should be recorded during the entire displacement, regardless of whether cement pumps or rig mud pumps are used to displace the plug. If possible, return rates should also be recorded. The recorded job data discussed in this section is necessary as a quality control record and for post job analysis and reporting. It can also supply valuable information in the event that the job can not be pumped as planned. 4.9.8 Lost Circulation Contingency Plans Lost circulation contingency plans should be discussed prior to job execution (see A.10). These plans can include increasing or decreasing cement volumes, altering cement thickening times, altering fluid loss control of the slurry, and increasing or decreasing slurry pumping and displacement rates. Computer aids such as surge analysis programs and ECD programs can minimize the risk of lost circulation. In addition, there are several float equipment designs that can be used to help reduce the risk of fracturing formations while running the casing into the wellbore. • 4.9.9 Spacers Cement spacer is one of the most critical components in obtaining successful zonal isolation. Spacers serve several functions including: — removing mud ahead of cement slurries, — water -wetting cement contact surfaces, — providing a barrier between the cement slurry and drilling fluid in the wellbore. Cement spacers should be tested for compatibility with a representative sample of the drilling mud. Improper spacer selection may result in poor mud removal and excessive viscosity at the spacer/mud interface. Multiple spacers may be recommended if compatibility cannot be established using a single spacer. The first spacer may aid in mud removal, while the second spacer water wets downhole surfaces and provides a barrier between the slurry and drilling mud. Spacers should meet density and viscosity hierarchy requirements as discussed previously. Adequate spacer volume is critical to the success of a primary cement job. Spacer contact time and/or annular fill should be discussed during job planning sessions. The spacer volume should be the greater of 5 minutes contact time (minimum) or 1,000 ft of linear fill. However, some situations may require that these spacer volumes be greatly increased. • 4.9.10 Displacement Cement slurries should be displaced at rates required for mud removal as determined from computer modeling unless lost circulation is encountered and contingency plans are initiated. The cement unit should displace all 0 40 API RECOMMENDED PRACTICE 65-PART 2 squeeze jobs, liner jobs, stab -in jobs, and plug jobs. The rig mud pumps can be used to displace large casing jobs, although the cement unit should monitor and record the displacement pressures. Displacement rates should also be recorded if possible, and methodically documented if recording is not possible. Over -displacing if the plug does not bump should be discussed prior to job execution. Volumes in excess of 50 % of the capacity of the shoe track should not be exceeded when pumping additional fluid over calculated displacement volume. 4.9.11 Multiple Plugs Top and bottom wiper plugs are recommended for all casing jobs, with the exception of stab -in casing jobs. On stab - in casing jobs, a drillpipe wiper dart or ball should be dropped behind the cement slurry. The spacer ahead of the cement slurry should be pumped ahead of the bottom wiper plug. This ensures that the cement is uncontaminated in the casing. In addition, double plug containers are recommended where possible. The wiper plug container should have a system to indicate the launch of the wiper plug. Trained personnel should follow established procedures when operating a cement wiper plug container. The top wiper plug should be launched as slowly as practical. Plugs should never be launched "on the fly." The wiper plug departure should be carefully noted, due to the potential for fluid bypass in some plug containers prior to plug launch. The top plug should be launched with spacer whenever NAFs are used as displacement fluids. 4.9.12 Holding Pressure Inside Casing • The casing floats should be tested after the displacement is complete. Once it has been determined that the floats are holding properly, pressure should be bled off the casing completely. Care should be taken to ensure that no pressure is trapped inside the casing due to closed valves on the cement head. Valves on the cement head should remain open as the fluid inside the casing will undergo heating and thermal expansion. If the valves on the cement head are closed, the casing will expand as pressure increases. Then, when the pressure is released, a microannulus may be created as the casing contracts, which could result in poor zonal isolation and SCP. It is typically not permissible to trap pressure inside the cemented casing unless the float valves have malfunctioned and are not holding pressure. 4.10 Post Cementing Operations 4.10.1 Maintaining a Full Hole and Cases for Applying Surface Pressure In order to maintain maximum overbalance pressure, the fluid level should be maintained in the annulus. In addition to maintaining the overbalance pressure, keeping the hole full will give an early warning if the well begins to flow. It also provides a means for tracking fluid losses in the annulus. Under some circumstances (see A.13), the controlled application, via pumping, of a constant pressure to the annulus can be used to mitigate well control events such as kicks and reduce the risk of a LWC incident. This surface pressure application increases pressure down the annulus to the source of the flow and helps create an overbalance across the flowing zone to mitigate or stop the flow. A technique (see A.15) that may also reduce the risk of an annular flow employs low pressure pulses applied to the top of the annulus. This method has been demonstrated to delay gel strength development to help prevent annular flows. Based on the start of its application in 2000, it has reduced the occurrence of annular flow in some wells, but 41 not all, for at least a few years. ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 41 Some specialized applications such as foam cementing or under -balanced operations may require that pressure be held on the annulus during WOC time. Job -specific procedures should be consulted to determine a pressure and time schedule for the annulus. The characteristics of the well, including depth, fracture gradient and geometry can play a role in the success of the above techniques. They are intended only to supplement other techniques used for control of flow. To be effective, the well should be rigged up and the technique started within a few minutes after bumping the top wiper plug which ends pumping for the primary cementing job. Care should be taken in washing out a riser, as this can reduce the hydrostatic pressure, leading to flow. 4.10.2 WOC Operations on the well following cementing should be done in such a way that they will not disturb the cement and damage the seal or cause the cement to set improperly. Any pipe movement to complete hanging the casing and activating seals should be finished before significant gel strength has developed. If done after the cement has developed significant gel strength, such pipe movement could cause a microannulus. There is also danger of initiating flow if the pipe movement swabs the well in. If the casing is to be hung after cement strength is developed, as when intentionally increasing or decreasing the landed tension in the casing, consideration should be given to the imposed forces on the cement and the cement strength. • Preferably, pressure testing casing should be done before significant gel strength has developed. However, such pressure testing will be limited by the pressure ratings of plugs, floats, cementing heads and other equipment. Pressure testing can be done after the cement has set but this can result in microannulus formation or damage to the cement sheath. The pressure should be held on the casing for the shortest length of time required to accomplish the test. The effect of pressure testing will depend on the properties of the cement, the pressure at which the casing is tested (and consequently the amount of enlargement of the casing) and the properties of the formation around the cement. Mechanical stress modeling can assist in determining the best time to conduct the pressure tests. Normally, a minimum compressive strength of 500 psi is recommended before drilling out the shoe of the cemented casing. See additional discussion of waiting on cement under Mechanical Barriers in 3.7.1 "Waiting Time Guidelines Prior to Nippling Down" through 3.7.4 "WOC Decision Tree." 4.10.3 Top Job A top cement job (that is, one conducted to fill in the annulus when cement did not reach the desired depth for the top of cement) can be conducted immediately after bumping the top wiper plug or it can be done after the cement has set. Consideration should be given to the probable poor displacement when a top job is performed. Because of poor displacement, it is unlikely that a top job will achieve effective hydraulic isolation. Every effort should be made to ensure that the primary job circulates cement to surface, when recommended, and a top job be done only as a last resort. If done immediately after bumping the wiper plug, formations deeper in the well may be broken down. The formations which might be broken down and the impact on the integrity of the well and the annular seal should be considered when using this method. • If the top job is done after the cement has set, consideration should be given to the method of placement, whether it is to be bullheaded or grouted. Bullheading requires breaking down a weak formation somewhere in the wellbore. If the cement has set and there is not a channel in the cemented annulus, the formation will break down between the top of • 42 API RECOMMENDED PRACTICE 65—PART 2 the set cement and the shoe of the previous casing. If the top of set cement is above the shoe of the previous casing, this method cannot be used. In such a case, the cement will have to be placed by grouting with a small diameter pipe run inside the annulus. If the top job is done by grouting comply with requirements in 3.7.4. 5 Leak Off Tests 5.1 Introduction Limit Tests (LT), also known as jug tests or formation integrity tests (FIT) and Leak -Off Tests (LOT), also known as pressure -integrity tests or pump -in tests (PIT) are carried out during the drilling phase after a string of casing has been cemented and before a new section of hole is drilled. In these types of casing shoe tests, the cement at the casing shoe is drilled out and a section of new hole (typically 10 ft to 20 ft) is drilled, the BOP is closed around the drillpipe, and the well is slowly pressured up using mud. Casing shoe tests serve the following purposes. — To confirm the pressure containment integrity to ensure that no flow path exists to formations above the casing shoe or to the previous annulus. If such a flow path exists, the casing shoe may have to be repaired (e.g. by cement squeeze). — To verify that a repaired casing shoe is sufficient. Repairing of a failed casing shoe test can be done by cement squeeze that seals fractures in the rock at a given depth interval. Repair by cement squeeze can also be done in the case where failure of the casing shoe test resulted from opening a mud channel in the annulus behind the casing. i— To investigate the capability of the wellbore to withstand additional pressure below the shoe such that the well is competent to handle an influx of formation fluid or gas without the formation breaking down. To collect data on formation strength and in -situ stress that can be used for geo-mechanical analyses and modeling (e.g. wellbore stability and lost circulation prediction). Most governmental regulatory organizations maintain criteria regarding verification of casing shoe integrity. Limit tests are carried out until a pre -determined test pressure is reached, confirming that the formation at the casing shoe can sustain this pressure. The test is characterized by a linear response of downhole pressure vs. volume pumped (or time if the flowrate during the test is constant). These tests are frequently used on production wells in mature fields, where fracture gradients are already well -understood. The limit test is used to confirm the margin necessary to drill the next hole section, without leaving a fracture (i.e. a potential point -of -weakness) at the previous casing shoe. LOT tests are carried out at higher pressures to characterize the phenomenon of "leak -off' into the formation at the casing shoe. Leak -off is characterized by a deviation from linearity on the pressure vs. volume curve. It is associated with the initiation of a fracture at the casing shoe. Pumping beyond the leak -off point will extend the fracture. A shut-in period is normally maintained after pumping to monitor the behavior of downhole pressure. During an extended leak - off test, backflow of drilling mud after shut-in is monitored in order to characterize in -situ stress values. Both LTs and LOTs may be repeated to verify the results of, or assess the changes induced by, earlier tests, drilling operations, and/ or remedial squeeze jobs. Note that if deviations from a linear response are observed in the pressure vs volume curve during casing shoe testing, the following potential causes should be evaluated and corrective action taken, as appropriate: • — leaks on the surface (e.g. chicksan connections, pump plungers); — fluid flow around the casing and cement caused by poor cement bonding and channeling; • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 43 — fluid seepage into formation in the open hole section; trapped air/gas or void space in the mud column; — non -linear deformation of rock being exposed to mud pressure; — fracture initiation and growth in the formation; — PVT effects (compressibility) of NAF (Ref: SPE 87155). 5.2 Pressure Integrity Test Procedures The following steps should be used when performing a pressure integrity test on a casing shoe. 1) Perform the casing integrity test per applicable regulations. 2) Prepare the operator -specified PIT/LOT form. Note the anticipated LOT on the form and/or a maximum test pressure if specified. Use a scale that will best utilize the entire plotting area of the form to help identify the break -over points. 3) Drill out the casing shoe, clean out the rat -hole, and drill 10 ft of new hole. 4) Circulate bottoms up to condition mud and stabilize properties, especially density. Be sure mud is free of air or gas bubbles. • 5) Pull up into casing a few feet. General industry practice is to not pump a slug of heavier mud or LCM prior to the test. 6) Rig up pumping unit and pump mud through test lines to purge air from the system. Pressure test surface lines checking for leaks. Use same pump that was used for the casing hydrostatic pressure test, if possible. 7) Close a BOP ram on the drillpipe. 8) Pump down the drill pipe at 1/4 or 1/2 barrel per minute (bpm) or other designated rate. Maintain constant pump rate throughout the test. 9) During the test, record and plot cumulative volume pumped vs drillpipe pressure for every 1/4 bbl pumped, regardless of the pump rate. Plot only the portion of the casing integrity test data to fit this scale. 10) Permeability in the open hole may cause pressure build-up to be non -linear (i.e. the plot curves and does not follow the trend of the casing test). If this occurs, stop the test, bleed pressure to zero and retest at a pump rate that is 1/4 to 1/2 bpm higher than the previous test. 11) Continue pumping until the predetermined maximum pressure is reached or until leak -off is confirmed. a) If pressure decreases sharply while pumping, stop pumping immediately. Check surface lines and valves for leaks (make any needed repairs) and attempt to retest. b) If pressure levels off far below recommended pressure or leak -off, pump additional volume (typically 1 bbl to 2 bbl) to see if a pressure increase will resume. 0 c) If performing a limit test, do not exceed maximum pressure specified. 12) When leak -off is confirmed, or maximum pressure is reached, stop pumping and close the shut-in valve. I-] 44 API RECOMMENDED PRACTICE 65-PART 2 13) Observe and record shut-in pressure vs time. Check surface lines and valves for leaks during this period. If any are found, repair and retest. 14) Release pressure and record the volume of fluid bled back. 5.3 Pressure Integrity Test Guidelines 5.3.1 Rigging 1) Pump Use a low -volume high-pressure pump (e.g. cementing unit). Do not assume that the mechanical barrel counter on the pump is accurate. Pump strokes are more reliable volume indicators if the pump is in calibration. The displacement tanks can also be used to monitor volume if properly marked in 1/4-bbl increments. 2) Shut-in Valve Use a shut-in valve between the pump and the pressure gauge. Use the shut-in valve rather than relying on the pump to prevent back flow. 3) Pressure Gauge A good quality calibrated pressure gauge is recommended. Use an electronic gauge or a mechanical gauge with the following features: liquid filled, 4 in. or larger, range from 25 % to 50 % greater than maximum • anticipated test pressure (the lower the better), from 10 psi to 50 psi increments (the smaller the better), and isolated from pump vibrations and pressure surges. 4) Purge Valve —Optional If testing without a top drive, install a purge valve on the pump -in sub and use to purge air from the test lines before initiating test. 5) Bleed Valve —Optional If possible, install a bleed valve on a tee between the pump and the shut-in valve. Open valve during shut-in period to see if the shut-in valve is leaking. 6) Pressure Test System Before PIT 5.3.2 Recorded Test Data The following items are generally recorded for each PIT. — well identification; — casing shoe depth (TVD/MD); — hole depth (TVD/MD); — casing size; 0 — hole size; — MW at surface; • — mud type; — test date; ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 45 test type (casing/FIT/LOT, etc.); — pump rate; — predicted leak -off or pressure limit; — fluid volume bled back; — water depth (offshore); — air gap (offshore). At a minimum, pumping data (pressure vs volume or time), casing shoe depth and mud weight are necessary for even a rudimentary interpretation of the test. Other data listed above are also useful in interpretation and comparison of tests. 5.3.3 Drilling Fluid Before pulling into the casing shoe for the test, circulate and condition the mud to stabilize properties and clean the hole of all fill. Circulate and condition for the shoe test. Insure that the mud weight out equals the mud weight in (t 0.1 ppg). Different mud types and formulations (e.g. water vs. water base mud vs NAF) can produce different PIT results due to fluid compressibility. Interpretation of repeat tests is simplified if drilling fluid types and properties are constant throughout. 5.3.4 Pumping Guidelines Pump rates of 1/4 to 1/2 bpm are typical for initial PITs. Larger volume tests may require higher pump rates. Pump rate should be constant throughout the test. Fluctuating pump rates can complicate test interpretation. 5.3.5 Shut-in Guidelines 1) Use the shut-in valve Using this valve rather than the pump will eliminate the possibility of fluid leaking past the pump during shut-in. As further insurance, monitor the shut-in valve (by means of the bleed valve) and other surface equipment for leaks. 2) Monitor pressure decline Monitor the shut-in pressure in 1 minute intervals until the pressure levels off or until it can be reasonably extrapolated to a constant pressure. A 10 minute to 15 minute shut-in is usually sufficient. If the pressure does not become constant after 15 minutes it is worth the time (for interpretation purposes) to wait until it does level off or declines to zero. 1* • 46 API RECOMMENDED PRACTICE 65-PART 2 5.4 LOT Technical References Technical references listed in Annex A (A.6 through A.16) provide further information on many topics related to leak - off testing, including the following: — definition and explanation of various types of pressure integrity tests (e.g. LOT, XLOT), fracture initiation, breakdown pressure, minimum horizontal stress, etc.; — factors that affect leak -off pressure, including rock properties, fluid type and properties, pump rate, and pre- existing cracks; — test interpretation; — effect of cement channels; — rig -up. This list is not all-inclusive. Other technical references are available in industry literature. 6 Post -Cement Job Analysis and Evaluation 6.1 Material Inventory One important aspect of the post job analysis is material inventory after cementing operations are complete. A final inventory of material should be completed and compared to the pre -job inventory as described in the cementing is execution section. The material mass balance will determine if the correct amount of cement and additives were used during job execution. 6.2 Job Data To further evaluate the cementing operations, the real time data can confirm fluid volumes, densities and rates in accordance with the initial design. Using computer aided design software, the acquired versus predicted can be compared to obtain pressure matching, equivalent circulating densities and confirm well security. When problems occur during the cementing operations, this information can be useful when investigating job failures. The information collected from the job should be compared to the predicted job design. Prior to the cementing operation, a checklist can be prepared from the job design to ensure all requirements have been achieved after execution is complete. The checklist should include all critical job information such as rates, volumes, densities, pressures, etc. All job data should be collected for a complete analysis and can serve as a reference for future wells drilled in the same or similar areas. Capturing the knowledge and sharing information with other operators could drastically reduce the number of flowing wells after cementing. 6.3 Cement Evaluation Formation integrity and cement placement and strength are important parameters to be evaluated before drilling the next hole section. Formation integrity tests are discussed under Leak off and Formation Integrity Testing in Section 5 and Annex A.10, 6th paragraph. • Failure to achieve a positive test may be due to inadequate seal by the cement in the annulus or failure of weak formations near the shoe. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 47 When the LOT or the FIT results are inadequate, the operator can perform a cement squeeze or chemical treatment such as formation consolidation or fracture sealant squeeze to enhance the formation's pressure containment integrity or to seal a leaking cement sheath in the annulus. A repeat LOT or FIT may then confirm the squeeze or treatment results in increasing the interval's wellbore pressure containment A more detailed discussion pertaining to formation integrity test procedures can be found in Section 5. In order to effectively evaluate a cement job, one should determine whether the objectives of the job have been achieved. The most obvious is supporting the pipe but other objectives will vary depending on the nature of the cement job. Some of these objectives include isolation to prevent erosion caused by annular flow of fluids, seal off and protect water formations, integrity to support deeper strings and to ensure zonal isolation. Based on the recommended objectives, multiple techniques are available which include temperature, noise, acoustic and ultrasonic cement logs. 6.4 Flow Prevention Practices Matrix Annex D contains a Flow prevention matrix for evaluating the potential impact of elements of the well construction process on the goal of attaining zonal isolation. The sheet should be completed by the operator during the planning of the well to help identify areas needing improvement. Then, as each hole section is drilled and pipe cemented, the parameters relating to that section are scored. At the conclusion of each string, the scores for each parameter should be evaluated again and used as a post job evaluation. The sheet can be printed at each of these stages and placed in the well file. The scores, both by major category and the total can be compiled in a database and, with evaluation of flow, used for process improvement. • 11 • Annex A (informative) Background and Technology A.1 Background On August 16, 2000, the Minerals Management Service (MMS) of the U.S. Department of the Interior presented safety concerns on uncontrolled annular flows to a new API Work Group. This group included government and industry representatives from several organizations including API Washington staff, API Executive Committee on Drilling and Production Operations, API Subcommittee 10 on Well Cements, International Standards Organization, International Association of Drilling Contractors, Drilling Engineering Association, the MMS, and other interested parties. Issues related to annular casing pressure (ACP) were also discussed. This new group called "API Work Group on Annular Flow Prevention and Remediation" agreed to document industry "best practices" to improve zonal isolation, reduce the occurrence of SCP, and help prevent annular flow incidents prior to, during, and after cementing operations. Studies of available information on flow event causes and prevention helped the Work Group write "best practice" documents for publication as API Recommended Practices. The API Work Group is responsible for the following API Recommended Practice publications: 1) API RP 65 (Part One) entitled Cementing Shallow Water Flow Zones in Deep Water Wells 2) API RP 65-2 (Part Two) entitled Isolating Potential Flow Zones During Well Construction (this document) • Another group has prepared API RP 90 providing guidance on managing ACP, if encountered. API RP 90 covers procedures such as ACP monitoring, diagnostic testing, establishing maximum allowable wellhead operating pressures (MAWOP), documenting ACP, and assessing risk to help determine the need for mitigation measures. API RP 90 refers to API RP 65 for more information on ACP prevention and remediation methods and materials. • A comprehensive overview of API RP 65 and its API Work Group (now a Task Group) is available in SPE paper 97168131. The following section summarizes some of the key issues studied by this API Group and addressed herein. A.2 Historical Data and Perspectives Historical data and verbal communications obtained from many countries strongly suggests that annular flows, gas migration, vent flows, ACP (both sustained and thermal annular casing pressure), pressure zone kicks, and LWC incidents, particularly prior to, during or after cementing pipe strings, can have grave consequences. Some of them have caused loss of human life and/or severe injuries, environmental pollution, loss of expensive facilities, and negative affects on the operator's future ability to obtain leases. Historical data also suggests that this is a common problem and presents an opportunity for governments, industry, and other contributing parties to work together on solutions. The API is committed to this task and continually works on relevant standard practices that help industry work safely and protect the environment. API's publication of a series of API RP 65 recommended practices is a key part of the solution by documenting proven technology that can mitigate and prevent annular flows linked to the well's casing installation and cementing process. Unforeseen events can happen on any cement job, even when it has been properly designed, so relevant well design parameters, drilling practices, redundant equipment systems, gas control cements, and/or other means of preventing these LWC incidents should be employed when the risk of hydrocarbon flow exists. The current trend to drill deeper HPHT wells heightens the concern for the risk of severe kicks and LWC incidents. Published annular flow study data from some countries is available from government and industry sources with examples from four countries listed below. 48 • • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 49 A.3 Studies of Annular Flows Primarily in the USA In 1964, Bearden et a11171 reported on an investigation of inter -zonal flows of formation fluids through the cemented annulus and methods to prevent them. This study concluded that the hydraulic seal of cements can fail when exposed to certain conditions. This type of failure is often due to low "bond" strengths or, in the worst case, a "micro - annulus" formed between the pipe and cement creating pathways for annular flows between high -/low -pore -pressure, high -/low -permeability formations. For example, say that cement is placed in the annulus across a potential flow zone and initially it has an internal pressure of 8000 psi caused by the hydrostatic head pressure of the column of cement or cement and mud above it. At the same depth and time, the hydrostatic head pressure inside the casing or liner pipe has a lower pressure of 6000 psi (called "casing pressure") from the lower density displacement drilling fluid or "mud." This gives a 2000 psi force pushing against the outside wall of the pipe which allows a hydraulic seal or "bond" to form between the cement and the pipe once the cement is set. Figure A.1 (Figure 3 from SPE 903) shows that this example cement seal can withstand over 1400 psi differential pressure between a nearby low pore pressure, permeable zone and the high pore pressure, permeable formation (potential flow zone) in the same annulus. NOTE The data curve in Figure A.1 should not be used to predict bond or hydraulic seal integrity as it only represents the data for one particular operator's cement slurry tested in one unique device that it not standardized. It serves here only to show how it helped one operator identify his specific zone isolation issues and solutions at a given time in history. For example, today the cements and additives together with the relevant slurry designs may now have different properties that would provide different "bond failure" data curves. G11I1I 7 H Ln ._ a In 0- 200 M 3 V V N C C C QJ c G U 41 3 -200i N N a1 d H -400 c c Q -600 mpg WAAMOMM01 MMMMMMI Bond Failure Pressure, psi: Reproduced with permission. Copyright, SPE. Bearden, W.G., Spurlock, J.W., Howard, G.C. 1964. Control and Prevention of Inter -Zonal Flow. J. Pet Tech 17 (5): 579- 584; SPE-903-PA Figure A.1—Effect of Curing Pressure on Bond Failure • 50 API RECOMMENDED PRACTICE 65-PART 2 On the other hand, if the initial 8000 psi hydrostatic head (HH) pressure within the cement is prematurely reduced before the cement has set hard and gained enough structural integrity, the hydraulic seal ("bond") can be substantially reduced or totally lost. For example, if the initial 8000 psi annular hydrostatic pressure is reduced to 4000 psi, the force against the outer pipe wall will be totally lost and a 2000 psi force (6000 psi HH csg. pressure — 4000 psi HH annular pressure) will then push against the inter pipe wall causing it to expand slightly in diameter. Figure A.1 shows that this change in direction of force (+2000 to —2000 psi) may reduce the potential hydraulic seal ("bond") strength from 1400 psi to less than 600 psi with the example cement. If this 600 psi is less than the inter -zonal differential pressure, an annular flow may initiate between the zones and also migrate further up the annulus via a micro - annulus. Also, if the 6000 psi internal casing pressure is sufficiently reduced after the cement is set hard, the pipe diameter may shrink enough to break the cement/pipe "bond" leaving an unsealed annular flow path or "micro - annulus" between the set cement and the casing's outer pipe wall. The more the hole/casing annular HH pressure is reduced during the cement curing phase, the greater chance for an annular flow. The risk of an annular flow also increases as the casing's internal HH pressure decreases after the cement's initial set. However, highly -gelled, unset cement may not deform and fail to maintain contact with the outer pipe wall when the casing diameter shrinks as internal HH pressure is reduced. Thermal effects may also create and/ or increase the size of a micro -annulus formed by the loss of annular or internal HH pressure. For example, casing and liners may have a micro -annulus formed or a larger one when: 1) holding pressure inside casing as cement cures (see 4.9.12); 2) the hole fluid level is not kept full (see 4.10.1); 3) moving the casing during WOC (see 4.10.2); • 4) the cement displacement fluid is replaced by a lighter density fluid; 5) the replacement fluid inside the casing is much cooler than the displacement fluid; 6) casing pressure tests or other imposed pressure applications are performed: a) after the cement starts to gain static gel strength (SGS) during WOC, b) after the cement sets at a test pressure above the cement's tensile strength, c) repeatedly during the life of the well that exceed the cement's fatigue limits; 7) mechanical seals are activated before the cement has gained enough structural integrity to resist pipe expansion from the loss of hydrostatic head pressure in the annulus. Some of the preventive measures mentioned by Bearden 161 included the use of float equipment, displacing with lighter density fluids, and, in some cases, attaching annular seal rings (type of mechanical barrier) to the casing. The latter method was proven successful in 25 out of 27 well applications. More preventive measures such as new types of annular mechanical barriers have been developed since then and are described in Section 3. Garcia and Clark 1181 disclosed the results of a seven year (1968 to 1975) lab and field study of annular gas flows in numerous wells to better define the issues, challenges, and recommend preventive practices. The significance of this study is the identification of annular flows in the 1960's by various investigators and postulating of the hypothesis or theory that of the loss of hydrostatic head pressure on top of and within the annular column of unset cement slurry was the root cause. A new cause for this loss of hydrostatic pressure was discovered and reported to be premature • setting or dehydrated "bridges" of a portion of the cement in the upper parts of the cement column. Another way to visualize this phenomenon is to think of these early set or bridging points as "artificial annular packers" made from cement or "annular cement packers." Included in the field study were cases where logs were used to identify and measure annular flows between zones after casing and liners were cemented. ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 51 Also during the 1960 to 1980 time period other investigators, Carter and Slagle 1191 and Christian et al 1201 presented substantial evidence of the cement packer effect also called "hydrostatic -pressure bridging" above potential flow zones that resulted in costly annular flows. In 1979, Tinsley et al 1211 identified continuing annular gas flow problems and associated costs from several tens to many hundreds of thousands of U.S. dollars per wells. Several years of research efforts to find solutions with associated field applications were summarized by Tinsley. One major finding was that compressible cement systems had positive results in reducing the occurrence of annular gas flow. Included in the field study were several offshore wells in the High Island area of the Gulf of Mexico where annular gas flow events after cementing surface and intermediate casing strings had caused uncontrolled releases of gas to the surface and to the atmosphere (called blowouts in the paper). Also land wells in South Texas were studied that had a history of annular gas flows after cementing production casing and liners causing communications between zones. Other areas with annular gas flows were identified that in low to moderate flow rate cases cause loss of production to thief zones above and/or below the production interval and in severe cases (also called underground blowouts) result in high risk conditions for safe well operations. Tinsley cited the researcher's consensus of opinion on the "annular cement packer' phenomenon mentioned above that "once pressure in the annulus has decreased by as little as 0.5 psi less than the formation pressure, gas flow can occur" and "this gas entry tends to form a gas channel in the cement column." Lab studies were presented that better defined how cement slurries can develop SGS which prevents transmission of hydrostatic pressure in cement columns. In addition to having "fluid -loss -controlled" cement slurry properties, Tinsley said that "free water' control in cement slurries, as identified by Webster 1��1, was needed for compressible cement systems to provide more comprehensive solutions to annular gas flow problems. This combination of cement performance properties was 90 % successful in preventing annular gas flows in over 200 well applications. Martinez et al 1231 studied the causes of annular gas flow and LWC incidents in Outer Continental Shelf (OCS) wells for the U.S. Department of Energy (DOE) and published a report on their work in 1980. This report is available at • 'http://www.mms.gov/tarprojects/027.htm'. This DOE study report includes case history reports on annular flows after cementing including "USGS" federal agency (pre-MMS) reports on LWC incidents that had similar causes to those disclosed herein API RP 65—Part 2. Also contained within API RP 65—Part 2 is more information on annular flow causes and up to date solutions to this challenge. The benefits of developing and/or implementing solutions to these issues were outlined on pp.6-7 in the DOE report and are still applicable today as follows: 1) safety improved by reduced risk from: a) underground blowouts, b) pressurized shallow sands, c) blowout adjacent conductor and potential loss of platform; 2) environmental protection enhanced by reduced potential for leaks to the seafloor or shallow formations; 3) economics: a) expensive blowout risk is reduced (as well as public loss of confidence in industry and agencies), b) reduced well control problems save drilling time and cost, c) remedial squeeze jobs are reduced. Martinez et al (231 also called for more research on why cement failed to control annular flows. As mentioned above, significant progress has been made since then to understand the relevant issues and to formulate solutions. Although most of the information in this DOE report is still relevant today, some parts may be updated as follows. 1) Page 4, no.4 Many laboratory and field studies have been published since 1980 that adequately describe cement hydration mechanics. Information from these studies helped developers make significant improvements • 52 API RECOMMENDED PRACTICE 65—PART 2 in cementing technology which are incorporated in the practices recommended in API RP 65 Parts 1 and 2. However, methods to measure set cement's mechanical properties are currently being studied by the API and others in order to standardize laboratory test procedures. 2) Page 10, C. on Unreliable Cement Slurry Mixtures —Same update as above no.1 and much more predictable and reliable cement slurries are available today including those designed to prevent annular flows. 3) Page 11, no.2 a. —Research on gas control cement properties in long columns of cement has been performed and reported in several studies cited herein. Laboratory tests to predict these properties and design gas control cements have been developed from these studies. Field cementing practices and materials have also been substantially improved by these studies. 4) Pages 19 to 20—SPE paper 8255 was cited as having good practices to design cementing compositions and field cementing practices. The above mentioned studies, many of which are described herein API RP 65--Part 2, have proven that the following cementing compositions and field cementing practices advised in SPE 8255 are not always technically valid. This uncertainty should be considered accordingly: a) Limiting the reduction in loss of unset-cement column hydrostatic pressure to no more than the cement mixwater density gradient and enhancing this gradient by additions of salt to the cement and/or cement mixwater is not valid (see A.13) based on downhole pressure sensor measurements by Cooke et al124,251 and others that show gradients can decrease below the cement mixwater density gradient. b) Applying pump pressure to the annulus during WOC to replace some or all of the loss of unset cement column hydrostatic pressure is not reliable in some cases (see A.13) based on downhole sensor • measurements by Cooke et a1124,251 showing surface applied pressures that fail to reach the downhole pressure sensors. Cement permeability was also evaluated as a potential factor in gas migration incidents by various investigators in the period from 1960 to the early 1980's. Cement permeability is a concern, but risks due to permeability can be mitigated by the use of additives. These slurries formed hard set, very low permeability cements which resisted adverse downhole conditions. Example cement slurries, lab tested under downhole conditions, have properties such as low fluid loss, no free fluid, no -settling, and short transition times for SGS development. Other design methods and associated additives are well known to those skilled in the art. Sutton, Sabins and Fau11261 in 1984 reported that maximum cement permeability of 12 mD found in several test measurements that could be substantially reduced by adding polymer type fluid loss control additives. Even without these additives, the reported 12 mD cement permeability calculates, with Darcy's equation, a migration time period that is too long vs. those encountered in field operations. This case can be explained by calculating migration travel times. The total travel time period (at 0.038 in./hr) for gas to migrate thru cement with high (12 mD) permeability in a 2000 ft long, annular cement column (p.3 of Sutton, Sabins and Faul [261 article) is calculated as follows: (2000 linear ft x 12 in./ft) - 0.038 in./hr = 24,000 in. - 0.038in./hr = 631,579 hours for gas to displace the cement's uncombined or free water in the pore throats of the cement's matrix permeability (12 mD). 631,579 hours - (24 hr/day x 365 days/yr) = 631,579 hr - 8760 hr/yr = 72.1 years total time period for gas migration through 2000 linear ft of 12 mD cement. The above 72 year gas migration time period removes cement permeability as a factor or cause for many gas migration occurrences. MMS statistics on well ages for SCP initiation (see graph in A.15) show that the vast majority of cases occur in less than 10 years instead of several decades like the 72 year example calculation above. • When cements contain materials that resist unfavorable downhole conditions and allow very low permeabilities to be achieved, gas migration travel time periods calculated with fractions of a millidarcy (mD) may be several hundreds or thousands of years depending on cement column lengths and differential pressures. Calculation of time to flow 0 • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 53 through permeability does not eliminate permeability as a concern, especially as permeability may act in concert with other wellbore or cement performance factors, such as communication with channels, high permeability pathways, etc. Additionally, filtrate water does not have to flow all the way to the surface, it can flow into shallow or shallower formations. Other factors may restrict annular gas flow and increase gas migration travel times such as a sealed and fluid filled annulus above the TOC that does not provide a vent for the cement filtrate water pushed out of the cement top by gas migration. A.4 Barrier Failure Study A study of LWC incidents in U.S. areas of the Gulf of Mexico OCS and some of the coastal states from 1960 to 1996 is reported in SPE/IADC 39354 by Skalle and Podio [27]. The many types of barrier element failures listed below in Table A.1 (from Table 6 of SPE/IADC 39354) may be prevented with the updated and proven practices described within this API publication. Note the higher total of failures for mechanical vs. cement types of barrier elements Table A.1—Most frequent Primary and Secondary Barriers that Failed in all Phases (Louisiana + Tx + OCS; 1960 to 1996) Primary Barrier BO Secondary Barrier BO Swabbing 158 Failed to close BOP 78 Too low mud weight 50 Rams not seated 14 Drilling break/unexpectedly high pressure 45 Unloaded too quickly 13 Formation breakdown/lost circulation 43 DC/Kelly/TJ/WL in BOP 5 Wellhead failure 40 BOP failed after closure 66 Trapped/expanding gas 40 BOP not in place 43 Gas cut mud 33 Fracture at casing shoe 38 x-mas tree failure 23 Failed at stab valve/Kelly/TIW 34 While cement setting 20 Casing leakage 23 Unknown why 19 Diverter—no problem 21 Poor cement 16 String safety valve failed 19 Tubing leak 15 Diverter failed after closures 17 Improper fill up 13 Formation breakdown/ lost circulation 15 Tubing burst 10 String failure 13 Tubing plug failure 9 Casing valve failed 11 Packer leakage 6 Wellhead seal failed 10 Annular losses 6 Failed to operate diverter 7 Uncertain reservoir depth/ pressure 6 x-mas tree failed 7 The high number of BOP failures, such as the "BOP not in place" and other types of BOP failures, was a key focus area for the API Work Group and is addressed accordingly within 3.7. For example, MMS regulation 30 CFR 250.422 (b) requires that if the operator plans to nipple down the diverter or BOP stack during the 8-hour or 12-hour WOC time period, the operator should determine when it will be "safe" to do so. The decision should be based on the operator's knowledge of the formation, cement composition, effects of nippling down, potential drilling hazards, well conditions, and past experience. Even though this regulation is currently in force, the API Work Group determined that more specific guidance (see 3.7) is needed since well control incidents, with this category (BOP failures) involved, are still occurring. • 0 54 API RECOMMENDED PRACTICE 65-PART 2 A.5 Studies of Annular Flows in the United Kingdom Hinton 1281 with the Offshore Safety Division of United Kingdom's Heath and Safety Executive reported in SIDE 56921 that 11 % of all wells drilled in the U.K. continental shelf from 1988 to 1998 have experienced reportable kicks during well construction operations. Of these 22 % were in HPHT wells (>10,000 psi and 300 °F). Other U.K. sources cited by Gao et al 1291 in SIDE 50581 claim that HPHT wells have much higher reportable kick incident rates (1 to 2 kicks per 1 well) compared to non-HPHT wells (1 kick per 20 to 25 wells). Some of the most frequent causes of kicks in drilling U.K. wells were also found in the U.S. wells such as lost circulation in the same hole section with potential flow zones, mud weight too low, and uncertainty in flow zone existence, flow potential, location, or other important characteristics. The following quote (SPE 56921, p.3, 1st paragraph) on other types of barrier failures during casing installation operations is significant. "Exactly half the kicks associated with casing operations occurred when liner laps or casing shoes leaked when mud weight was reduced." The liner lap failures mentioned in SIDE 56921 included one case history of a well with a 7,500 psi shut in drill pipe pressure caused by a leaking liner top packer. These two types of barrier failures (liner laps and casing shoes) present opportunities to help prevent future incidents by implementing the updated guidance on proven practices contained herein. A.6 Studies of Annular Flows in Canada Gas migration is reported by the Canadian government authorities to exist in many wells in Canada. A recent article by Lang 1301 reported on annular flows in Canada's shallow to moderate depth wells in the areas of Alberta and Saskatchewan "historically have had problems with gas migration developed leaks after primary cementing in 57 % of the cases, on average." In 2003, Getzlaf and Watson (311 stated that a database that registers gas migration in Alberta "currently has over 5000 recorded vent flows, some serious, but most recorded as non -serious." A vent flow is the local name for an annular gas flow. In the time period from April 1998 to March 1999, the Alberta Energy and Utilities Board [3�1 cites the following LWC statistics for 7094 new wells drilled and included in the new total of over 129,000 active wells. Table A.2—Drilling and Service Well Control Occurrences, 1998/1999 Drilling Servicing Blowouts 9 1 Blows 1 Kicks 101 N/A The latest AEUB [331 report posted on their website is for 17,108 new wells drilled in 2003. Table A.3—Drilling and Service Well Control Occurrences, 2003 Drilling Servicing Blowouts 1 4 Blows 3 7 Kicks 106 N/A The 2003 statistics compared to those in 1998 and earlier periods continues the favorable trend in recent years showing substantial decreases in the occurrence of blowouts (also called LWC) and kick incidents (a type of annular flow) during the drilling of new wells. 0 ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 55 The AEUB 13�1 reported gas migration and surface casing vent flows (also called casing pressure) of gas as follows in Table A.4 and Table A.5. Table A.4—Surface Casing Vent Flows Year Serious Non -serious Total 1995 393 3121 3514 1996 75 3103 3178 1997/1998 76 3537 3613 1998/1999 139 3671 3810 Table A.5—Gas Migration Problems Year Serious Non -serious Total 1995 4 596 600 1996 6 809 815 1997/1998 6 801 807 1998/1999 1 813 814 Of the 7667 wells that applied packers to maintain well integrity, relatively low numbers of leaking packers were identified in the mandatory packer isolation testing and reporting program [3�1 as follows in Table A.6. Table A.6—Packer Isolation Testing and Reporting Program Results Notice of suspension Closure orders issued Repeatcompanies Abondonment orders letters issued for closures issued Year Companies Wells Companies Wells Companies Companies Wells (no.) (no.) (no.) (no.) (no.) (no.) (no.) 1995 N/A N/A 51 172 N/A 20 34 1996 N/A N/A 137 446 24 11 1997/1998 90 180 15 23 3 1 1 1998/1999 128 443 22 34 6 2 2 A.7 Studies of Annular Flows in Russia A study by Krylov [341 reports an analysis of data on monitoring annulus pressures (AP) of wells at the Karachaganak gas condensate field. Development drilling began in 1985. The analysis showed that AP is found in wells regardless of their category —operating or shut-in. The percentage ratio of wells with AP to the total stock was calculated for both well categories for the purpose of studying the dynamics of wells with AR The data show an increase of the percentage of operating and shut-in wells with AP from 45 % and 1 % in 1993 to 56 % and 33 % in 2000, respectively. Assumptions about the causes for the increase of wells with AP are given in the study report. A.8 LWC Insurance Database Studies Studies by Adams 1351, Adams and Young 1361, and Jackson [371 (Willis Ltd.) provide information that helps explain • some of the causes, cause effects, and costs of LWC incidents. Adams states that "About 65 % of all blowouts are 0 56 API RECOMMENDED PRACTICE 65—PART 2 0 UGBOs (underground blowouts)." and "Flows originating behind casing after cementing are perhaps the second most common UGBO cause." Adams and Young report the following. — "UGBOs occur about 1.5 to 2 times more frequently than surface blowouts. Cumulative costs are believed to far exceed that for surface blowouts." — "A common flowpath is a poorly cemented casing-openhole annulus." "The danger associated with this flowpath (poorly cemented annulus) is the circumvention of the primary well - control hydraulic system of the hole, casing and BOPs." Adams and Young cited Willis Energy Loss Database 1371 analytical reports for the costs of 1,224 LWC incidents all with financial loss claims greater than one million U.S. dollars. The well loss incidents include blowouts (-90 % of total), mechanical failure, stuck drill pipe, fire/lighting/explosion, heavy weather, design/workmanship, collisions and others. Table A.7 from Adams and Young's World Oil article 1361 shows LWC incident costs by the status of the wells. OEE in the table means operator's extra expense. The intent of the table is to identify where more focus should be placed relative to blowout prevention measures in the future. Drilling operations (includes cementing) has the highest number of incidents at 668 out of the total of 1,224. Table A.7—Well Status at Time of the Incident Status of well Incidents OEE actual US$ Average OEE actual US$ Abandoned 3 45,383,105 15,127,702 Completion 17 106,722,607 6,277,800 Drilling 668 4,396,562,496 6,581,680 Plugging 3 11,165,400 3,721,800 Producing 82 1,045,737,073 12,752,891 Shut In 14 134,887,062 9,634,790 Workover 42 319,808,465 7,614,487 (Unknown) 393 2,029,815,203 5,164,924 Other 2 8,100,000 4,050,000 Total 1224 8,098,181,411 6,616,161 More LWC incidents are caused by natural gas formations based on the data shown in Adams and Young's 1361 Table A.8. The type of blowout fluid was not known for the 500 incidents listed under unclassified well types. This is often the case for underground blowouts. The highest frequency of LWC incidents occurred in wells between 7500 ft. and 14,999 ft. deep according to the data that Adams and Young 1361 present in Table A.9. Discussions in April 2006 with Andrew Jackson at Willis Limited provided an updated well population in the Willis Energy Loss Database, i.e. includes 1381 well loss incident claims of which 1237 wells are LWC incidents or blowouts (501 underground blowouts, 308 surface blowouts, and 428 unknown). Jackson said that certain types of data needed to pin -point the root cause of incidents are not captured in the database and may only be available from the well owner/operator and/or the insurance claims adjuster for the specific case. • 0 ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 57 Table A.8—Blowouts by Well Type Well type Incidents OEE actual US$ Average DEE actual US$ Gas 536 3,732,864,691 6,964,300 Oil 86 560,968,996 6,522,895 Oil & gas 86 1,069,809,755 12,439,648 Sulphur 3 14,443,297 4,814,432 Sulphur 1 3,330,000 3,330,000 Water 9 39,643,956 4,404,884 Other 3 23,100,000 7,700,000 Unclassified 500 2,654,020,716 5,308,041 Total 1,224 8,098,181,411 6,616,161 Table A.9—Blowouts by Depth Category Depth (ft) Incidents Total actual OEE US$ 0 to 4,999 95 795,786,456 5,000 to 7,499 69 558,347,594 7,500 to 9,999 126 567,598,068 10,000 to 14,999 345 1,555,519,961 15,000 to 19,999 183 1,838,981,875 20,000+ 28 397,994,687 Unclassified 378 2,382,952,770 Total 1224 8,098,181,411 A.9 Summary of API 65 Work Group's Study of 14 LWC Incidents In API 65 Work Group 13) meetings, annular flow statistics on offshore wells in U.S. federal waters were presented including MMS records on the occurrence of SCP and on 34 LWC incidents that occurred during drilling operations and reported in the years 1992 through 2002. Of the 34 LWC incidents, 19 (56 %) were caused by annular flows associated with the cementing process. The API Work Group 131 studied 14 of the 19 LWC incidents linked to cementing that occurred from 1996 to 2001 on the U.S. outer continental shelf (OCS), i.e. annular flow events during or after cementing operations. Conclusions of the study of the 14 incidents are listed below. 1) Most of the LWC incidents studied took place during or just after cementing surface casing. 2) In more recent years (2003 to 2004), these events involved deep casing strings with no occurrence of LWC incidents in surface casing cementing operations. 0 3) Most wells used a mudline hanger/suspension system. 0 58 API RECOMMENDED PRACTICE 65—PART 2 4) Frequently the annulus between surface and conductor casings at the surface was washed out to a point 30 ft to 50 ft below the mudline after cementing. Washing out this annulus resulted in a small but possibly very significant reduction in hydrostatic pressure while also impairing the operation of the BOP and diverter (wash pipes in the annulus prevents sealing). 5) Often, cement slurries were not designed to prevent flows. 6) Effective mud removal and zonal isolation practices were not followed. The study included reviews of detailed information on the incidents including "lessons learned" presentations by many of the operators involved. Public documents were available for some of the incidents that reported causes and proposed preventive measures. The studied incident information and the membership's knowledge of annular flow events in other areas allowed the Work Group to prepare proven practices contained herein to help prevent future annular flow incidents and also help reduce the occurrence of SCP. A.10 Lost Circulation Increases Risk for LWC Incidents Lost circulation before, during, or just after primary cementing. a) Can cause a failure to maintain an overbalance across potential flow zones exposed in the wellbore whereby: 1) an inadequately designed cement slurry (density too heavy, etc.) fails to reach the designed depth for the top of the cement (TOC) column; 2) or the drilling fluid column is reduced or "falls back" or "goes on vacuum;" 3) and either one of these shortened columns results in an insufficient hydrostatic head pressure to overbalance formation(s) pore pressures. b) Has often been found by investigators as the root cause for many of the LWC incidents experienced in offshore drilling operations. c) Can induce LWC incidents at any depth in the well construction process from soon after "spudding" (starting to drill) the well to drilling the well at total depth when conditions occur such as: 1) structurally weak zones are exposed in the wellbore; 2) naturally occurring leak off flow paths are encountered such as fractures, faults, vugs, caverns, etc. As mentioned above, lost circulation during primary cementing operations may cause reduced hydrostatic pressure and underbalanced conditions when losses cause the mud column to fall to create an underbalance. For example when heavier density (than the mud) cement slurries are removed from the annulus by total or partial lost circulation (cement flows into weak zones), the TOC can be much lower than the designed top of cement depth. This substantially decreases the annular column hydrostatic pressure across potential flow zones within the cemented annulus. This decreased hydrostatic pressure allows formation fluids to influx into the wellbore which starts annular flows that can lead to LWC incidents. Another way for lost circulation during cementing operations to lead to LWC incidents is when the actual TOC does not reach the planned depth to cover potential flow zones and, instead, places drilling fluid across these formations. If the drilling fluid hydrostatic pressure is below the formation's pore pressure, annular flows may start immediately. If the drilling fluid hydrostatic pressure is above the formation's pore pressure, an annular flow may not start until mud gellation (also called SGS development), solids settling, etc. decreases the hydrostatic pressure enough to create an underbalanced pressure condition. See A.14, 4) for more information on this phenomenon. ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 59 Cement channeling may cause total or partial lost circulation during primary cementing by initially raising the cement column to longer than planned heights (shallower depths) which results in pressures (ECD or ESD) greater than fracture initiation/propagation pressures. Relevant formations exposed to these pressures then "breakdown" or fracture and start taking volumes of the cement slurry out of the annulus. When this occurs, the annular fluid level drops (called "fallback") or the annular fluid flow rate out of the well decreases to less than the rate pumped into the well. In either case, the risk of an LWC incident increases when these losses result in underbalanced pressure conditions across potential flow zones. Applying adequate measures to prevent cement channeling and associated losses are described herein including methods to optimize mud and cuttings removal/displacement by operational procedures and cementing job designs such as measuring mud conditioning and hole cleaning performance with fluid calipers (see 4.8.4), pipe movement, installing centralizers, and pumping relevant cement flushes and spacers at engineered rates. An API cementing book [381 published in 1991 includes data (see Table A.10) indicating that up to 45 % of all wells require an intermediate casing to prevent severe lost circulation while drilling to total depth (TD). With these extra pipe strings in well designs, lost circulation events still occurred in 18 % to 26 % of all hole sections. Some areas reported many more occurrences of lost circulation events ranging from 40 % to 80 % of wells. In recent years, these percentages have likely increased as the number of shallow, easy -to -find reservoirs has steadily declined and well operators have intensified their search for deeper reservoirs and drilled through depleted or partially depleted formations. Conventional LCM including pills, squeezes, and pre -treatments, and drilling procedures such as ECD management often reach their limit in effectiveness and become unsuccessful in the deeper hole conditions where some formations are depleted, structurally weak, or naturally fractured and faulted. In some cases, operators perform FIT or LOT measurements (see Section 5) after the initial casing shoe test while drilling critical hole intervals or after drilling the entire hole section. This practice helps confirm that lost circulation can be prevented by the integrity of the open hole to contain pressures generated from deeper drilling and/or from operations to set casing/liner pipes (higher ECD in running pipe and primary cementing). Successful cases over the last 50 years have proven that this practice can successfully predict cementing placement without losses. In other cases when cement losses are predicted by the hole section FIT or LOT, the operator may decide to apply alternative measures such as LCM pills, tack and squeeze, etc. Some technical papers describe these practices including the lessons learned procedure reported by Rederon et al 1391 in SPE 149 (p. 5, rt. Column, step no.1) published in the late 1950's. More on lost circulation and recommended practices to measure and control it are in 4.3, 4.5, 4.6.3, 4.6.5.9, 4.7.3, 4.8.2, 4.8.2.3, 4.8.4, 4.9.8, 4.10.3 and Annex sections B.2.2, B.2.6.1, B.2.9.4, C.2, and C.3. Table A.10-1991 API Survey Data on Lost Circulation United States North America Global Producing fields in survey 204 218 339 Wells needing intermediate casing and/or drilling liner 31 % 33 % 45 % Lost Circulation Encountered Surface casing 24 % 24 % 21 % Intermediate casing 24 % 25 % 23 % Production casing 24 % 24 % 24 % Liners 18 % 26 % 19 % • • 60 API RECOMMENDED PRACTICE 65-PART 2 A.11 Example LWC Incident Case After Primary Cementing Operations A drilling rig had completed cementing surface casing. Shortly after the surface/conductor casing annulus was washed out, the annulus began flowing. Rather than release the flow into the diverter system, the crew attempted use the diverter to hold pressure to allow time for the cement to heal. To hold pressure, the diverter was placed in the "test" mode, which allowed both the diverter packer element and vent -line valves to be closed simultaneously and immediately. The diverter in use featured a telescopic riser with seals bracketing the vent -line housing. When the diverter was closed, the pressure rapidly increased until the seals began leaking, forcing abandonment of the rig floor. It was then discovered that the "test' mode disabled the ability to control the diverter system from the remote location. Seal pressure could not be increased to contain the surface leak; the diverter valves could not be opened to relieve the pressure. With gas on the rig and pressure rising on the untested conductor casing shoe, the rig and adjacent platform were evacuated. Several factors contributed to the potential severity of the event, including an erroneous chain of decisions, inadequate training of personnel, minimal knowledge of diverter system, and poor planning. There were 20 diverter incidents in the Gulf of Mexico from 1973 to 1995 related to well kicks after cementing surface casing. Another 13 similar incidents have occurred since 1995, with the most serious consequences being gas broaching to the surface, cratering, well loss, and rig and platform destruction by fire. Annular flow related to cementing surface casing has been identified as one of the most frequent causes of loss of control incidents in the Gulf of Mexico. Additional examples of such well control incidents can be found at http://www.mms.gov/incidents/ blowouts. htm. . A.12 General Review of Key Technologies Achieving zonal isolation in the presence of a potential annular flow requires not only the modification of the cement properties to facilitate control of migrating formation fluids but also several other features including: — a stable wellbore—no losses or gains, — adequate annular circulating flow clearances, — proper mud conditioning and hole cleaning prior to cementing, — spacer design, — casing centralization, — proper fluid dynamics during circulation and placement of cement to achieve mud removal, — tripping requirements, — drilling techniques, — well monitoring, — proper WOC time and associated rig operations, — sustained hydrostatic pressure during cement curing, 0 • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 61 — no wash pipes in the annulus that negates BOP function, — use of mechanical barriers when appropriate. This document is a compilation of best practices, engineering considerations and cement property requirements to assist in the prevention of annular flows and to establish zonal isolation within the wellbore. This task entails, at its most fundamental level, the removal of mud from the wellbore and replacement of mud with cement capable of achieving and maintaining annular isolation. During the API Work Group's study and draft RP preparation process, the relevant technology and practices contained herein generated prolonged discussions and comprehensive work in writing the relevant text in this and other parts of API RP 65—Part 2. Numerous literature searches were conducted to find, discuss, and cite the information that helps document whether or not a practice is field proven, technically valid, and reliable in preventing annular flows. A.13 Loss of Hydrostatic Pressure After Cement Placement The failure of an annular cement column to control and isolate zones exposed in the wellbore is the root cause for many of the LWC incidents experienced in offshore drilling operations. LWC incidents can occur at any point in the well construction process from soon after spudding the well to drilling the well at total depth. A number of factors are common to LWC incidents experienced while drilling the top -hole sections. From a pressure maintenance standpoint, many wells are drilled in a near -balanced condition. Often only a minimal pressure margin exists between formation pore pressure and circulating hydrostatic pressure of the drilling fluid. Typically, the well is drilled with simple spud muds with minimal fluid loss control. The cement designs employ lightweight, extended lead cement systems with a tail cement of higher density placed in the lower section of the cemented interval. In common 40 practice, both lead and tail cement slurries are designed without any gas control capabilities. Further, certain lightweight and other cement systems are prone to gel before setting, thereby causing and accelerating the loss of hydrostatic pressure exerted on the column of tail cement below. A detailed discussion of this phenomenon is included in A.13 and A.14 where the "loss of hydrostatic pressure" effect can be caused by pre -mature gellation, also called early static gel strength development of the "critical gel strength period" (see 4.7.8)1181. Annular flows have been caused by hydrostatic pressure losses that occur before the cement cures into a hard, impermeable barrier. This has happened in both top -hole sections and bottom -hole sections of the well. Several factors or combinations may cause annular flows in the deeper sections of the well including the cementing process, cement design, and the immediate setting of mechanical barriers that can reduce hydrostatic pressures. While mechanical barriers are designed to prevent the flow of annular fluids past the barrier element or seal, setting of the barrier may actually increase the chance of gas entering the cement slurry. This is because setting the barrier isolates all potential flow zones below the barrier from all of the hydrostatic pressure above the barrier. This reduction in OBP on any potential flow zones effectively decreases the CSGS as defined in 4.7.8. The pressure in the annulus therefore drops to the pore pressure of the flow zones at an earlier time after the cement is in place, increasing the window of opportunity for gas to enter the cement slurry. Because of this increased chance of gas entering the cement, it is very important that the slurry placed across potential flow zones is designed with gas migration control properties (see 4.7). Properly designed cement slurries should be used to help prevent the gas from migrating through the annulus once it has entered the cement. If migration is not controlled there is potential for either a cross - flow into a lower pressure zone or the collection of a gas pocket directly below the mechanical barrier. In other cases (no mechanical barrier), annular hydrostatic pressure losses may fall below permeable formation pore pressures resulting in underbalanced conditions that cause higher pressure formation liquids and gases to flow into the cemented annulus. This can lead to annular flows of formation liquids and gases which may induce cross -flows into permeable formations with lower pore pressures, paths that flow up to the wellhead, or a combination of both. Cooke et al [24,251 investigated the loss of hydrostatic pressure in columns of mud and cement slurries and reported the results in SPE papers 11206 and 11416 and in JPT articles dated August 1983 and December 1984. Cooke • 62 API RECOMMENDED PRACTICE 65-PART 2 studied hydrostatic pressure losses by measuring annular pressures vs. time at various depths with sensors installed on the casing and hard wired to surface recorders. Measurements were recorded prior to, during, and after primary cementing operations in several wells. Measurements were recorded for several months in some wells that showed long term reductions in mud column hydrostatic pressures. Cooke's study [24,251 discovered fundamental mechanisms and explanations supporting some theories on loss of hydrostatic pressure and invalidating others. These discoveries were verified by others such as a similar separate downhole sensor study (SPE 19552) by Morgan [401 while running and cementing casing in the North Sea. Morgan also reported how these downhole measurements indicated the failure to set an ECP. An analysis of downhole annular pressure measurements can explain other difficult to find or complex root causes for other cause effects such as high ECD pressures when cementing liners. Brehme et al [411 et al found that downhole pressure sensor measurements are a reliable method to help diagnose and evaluate liner running and liner cementing operations. Cementing simulation computer model results were favorably compared to the actual downhole pressures. Brehme et al [41] proposed this process to help predict and evaluate results in future cementing operations by downhole gauge diagnosis of conditions not included in software models such as annular restrictions by cuttings, hole cleaning performance, and liner hanger equipment functions. For example, this data can help operators find answers for some annular flows linked to lost circulation events such as those caused by complete or partial flow restrictions in liner laps or liner hanger bypass or cross -sectional areas plugged by cuttings not removed during hole cleaning operations. A.14 Some Key Results from Cooke's Study [24,25 Some of the key results from Cooke's study [24,251 are as follows. • 1) Downhole sensor measurements proved that the loss of hydrostatic pressure in columns of unset cement may be reduced to values below those found in cement mixwater (fresh, sea or saltwater) density gradients [see A.3, no.4.a)]. See Figure A.2 (Figure 9 in SPE 11206) showing that the cement hydrostatic head from the sensor at 1900 ft. in well G decreased from 13.4 lb/gal to 2.5 lb/gal equivalent density in ca. 420 minutes. This measurement is 6.0 lb/gal equivalent density below the average seawater gradient of 8.5 ppge. Cooke concluded that SGS development caused the cement hydrostatic head to regress to 2.5 ppge based on hole conditions such as formations with little or no permeability across and above the sensor at 1900 ft. This invalidates the idea claimed in SPE 8255 [421 that the loss of hydrostatic head in the cement column never falls below the cement's mixwater density gradient. It also invalidates the associated practice [381 of adding salt in cement slurries to increase the gradient and reduce the loss of hydrostatic head. 2) Surface pressure applied to the annulus may not reach the desired depth depending on mud and cement properties such as gel strength development (A.3, no.4.b. and 4.7.8). See Figure A.3 (Figure 4 in SPE 11206) that illustrates the lack of pressure response in 3 sensors at 4430 ft, 5454 ft, and 7412 ft in well B when surface pressure is applied. Also notice the large amount of pressure applied after 2100 minutes was high enough to break the cement SGS and allow hydrostatic pressure to be measured at 2 of the 3 sensors. Figure A.3 (Figure 2 in SPE 11206) also shows no pressure response from all sensors in well A by the applications of surface pressure designed to test the validity of said practice described in SPE 8255 [421. The surface pressure was applied 24 minutes after the cement job ended. This uncertainty in transmitting hydrostatic pressure through unset cement slurry at various times during a cement's curing phase makes it unreliable to carry out the practice of applying and maintaining an annular surface pressure to compensate for hydrostatic head pressure losses as claimed in SPE 8255 [42]. Therefore, applying surface pressure by pumping into the top of the annulus should be considered only for well control purposes such as controlling a kick in the annulus. However, in some recent cases (4.10.1 and A.15) applying small amounts of surface pressure in the form of controlled pressure pulses has worked in some wells to help prevent annular flows when the entire process, including the cement system, is properly engineered, understood by all involved, and validated by relevant means such as the lab testing is described in 4.7.8. 1] a LL m m `m a E 9 130 120 110 100 90 80 ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION Pum Completed Sensor Depths - ft 4432 4326 4034 41111111— 2900 1900 �=2.5 lgal r� 4432 & 4034 4326 2900 Geothermal 1 • J90a Time - Hundreds of minutes 63 Reproduced with permission. Copyright, SPE. Cooke Jr., C.E., Kluck, M.P., Medrano, R. 1983. Field Measurements of Annular Pressure and Tem- perature During Primary Cementing. J. Pet Tech 35 (8): 1429-1438; SPE-11206-PA. Figure A.2—Annular Pressure and Temperature —Well G 3) Prior to Cooke's study [24,25] our industry did not have relevant field data to fully understand and confirm the theoretical mechanisms accounting for the rapid losses of designed overbalances after cementing jobs. Cooke's measurement of this rapid decrease in cement column hydrostatic pressures to underbalanced conditions across potential flow zones helped explain the cause of many LWC incidents. It also helped explain how other annular flows such as cross -flows and underground blowouts were initiated. The understanding of how SCP may initiate via different types of annular pathways was also improved. Figure A.4 (Figure 2 in SPE 11206) presents annular pressure and temperature measurements in well A that illustrate how the hydrostatic head decreased vs time. Note that the hydrostatic head loss in all sensors started immediately after pumping of the cement slurry ended and the temperature at each sensor indicated that the cement was not set until inflection points in each temperature curve was recorded. These inflection points represent the principal exotherm of the cement that occurs when the cement achieves initial set. In 1983 all the information from Cooke's study was an industry revelation that helped accelerate the implementation of cement practices and materials that were already developed to help control annular flows. It also helped R&D funding by various companies for even better solutions. 4) Many other interesting facts and data analysis results are presented in SPE 11206 and the follow-up paper SPE 11416. The latter one focused on temperature effects, lost circulation during cementing diagnostics, and the hydrostatic pressure decline in columns of "mud" or drilling fluids. Figure A.5 (Figure 7 in SPE 11416) indicates the mud hydrostatic head loss recorded by sensors above the TOC during many days after the cementing jobs in wells B and D. • 64 API RECOMMENDED PRACTICE 65—PART 2 • 6000 5000 a 4000 d m 0 3000 2000 1000 0 LL 200 d 150 a E H 100 Pumping Completed Sensor Depth - It 7412 5454 5454 4430 2904 2232 979 01 7412 b454 979 11 12 13 14 15 16 17 18 19 20 21 22 23 Time - Hundreds of minutes Reproduced with permission. Copyright, SPE. Cooke Jr., C.E., Kluck, M.P., Medrano, R. 1983. Field Measurements of Annular Pressure and Temperature During Primary Cementing. J. Pet Tech 35 (8): 1429-1438: SPE-11206-PA. Figure A.3—Annular Pressure and Temperature —Well B This unexpected loss of mud hydrostatic head has two major impacts on well design practices: a) the "initial density of the mud in the annulus should not be used as the backup pressure in casing burst design," b) the mud hydrostatic head based on the original mud density should not be counted on to overbalance potential flow zones during the life of the well. During the late 1980's, Cooke's study [24,25] was favorably peer reviewed by API's Subcommittee 10 on Cementing and recognized as one of industry's most important publications for the advancement of cementing technology. Accordingly, its significant findings and data measurements were published in API's book 1381 on cementing practices in 1991. • �J a 7 6 3 2 220 200 LL 180 m E 160 140 120 800 Sensor No. Depth (ft) (RKB) ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION I 1 Pumping Completed Times when each sensor returned to measured mud weight 4 5 1 900 1000 1100 1200 1300 1400 Time - Minutes 1 2 3 4 5 6 8754 6909 5488 4787 4632 3636 (0 d d 0 Reproduced with permission. Copyright, SPE. Cooke Jr., C.E., Kluck, M.P., Medrano, R. 1983. Field Measurements of Annular Pressure and Tempera- ture During Primary Cementing. J. Pet Tech 35 (8): 1429-1438; SPE-11206-PA. Figure A.4—Annular Pressure and Temperature —Well A 65 • 66 API RECOMMENDED PRACTICE 65—PART 2 11.5 11.0 1 10.5 + Well D Well B 10.0 i 9.5 9.0 0.1 1 10 100 • Time - Days Reproduced with permission. Copyright, SPE. Cooke Jr., C.E., Kluck, M.P., Medrano, R. 1984, Annular Pressure and Temperature Measurements Diagnose Cementing Operations. 36 (12): 2181-2186; SPE-11416-PA. Figure A.5—Mud Densities Measured By Pressure Sensors in Annulus A.15 Studies on Pressure Pulsing to Help Prevent HH Loss After Cementing A new method, designed to mitigate unfavorable development of cement slurry SGS, applies low (80 psi to 200 psi) annular pressure pulses every 30 seconds to 60 seconds which has shown some degree of success in reducing the occurrence of the SCP type of annular flow. This method has been demonstrated to delay gel strength development to help maintain a hydrostatic pressure overbalance across potential flow zones during WOC time periods also called the cement curing phase. It has reduced the occurrence of annular flows in some wells, but not all, for at least a few years based on reports since its initial application in 2000. Stein et al 1431 reported the results of pressure pulsing applications to prevent annular flows or "leaks" (the type API calls SCP or sustained casing pressure) in Canadian wells as shown in Figure A.6. The flow/no-flow or "leaking" status of pressure pulsing applications in the Canadian wells presented in the figure above is for a time period of 1 year to 3 years after the wells were cemented and completed. The category of wells expected to leak without pulsation is based on history of leakage in the offset wells. In some cases, SCP may not occur for many years. Therefore, it is important to continue to watch for SCP initiation in all of the pressure pulsed wells so that this new method can be better evaluated. 0 • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 67 Abbey llndbergh -- ----- -._.T, Tangleflags Immo"--' Wlldmere Cabn --`� Miry Creek Neves Whrtecourt Laudens Paddle River ;ig.t Buffalo Creek ow ._ Total Wells Pulsed ■ Wells Expected to Leak wlo Pulsation X Wells Actually Leaking after Pulsation 0 S 10 15 20 25 Number of Wells Figure A.6—Summary of the Top 11 Fields Pulsed in Canada • LJ 30 Annex B (informative) Well Planning and Drilling Plan Considerations 13.1 Evaluation of Well for Flow Potential B.1.1 General Before drilling a well, the operator should attempt to identify and analyze potential flow zones. A variety of techniques are available to do this, three of which are discussed below. The success of these techniques in identifying and successfully dealing with flow zones is related to the quality of the available data, a company's experience in a specific geographical area, and the capabilities of the personnel involved in the analysis. 6.1.2 Site Selection Prior to drilling, the operator can minimize encounters with potential flow zones by carefully selecting a site that achieves target depth while minimizing the risk of encountering a flow. This is accomplished primarily through accurate review and analysis of available shallow and deep hazards data, proper interpretation of this information, and assimilation of this information into the drilling program. Offset well information (when available) should be evaluated to determine if flow zones were encountered, the magnitude of any flow events, and the methods used to mitigate the effects of these flows. This information should be • incorporated into the current drilling program. API RP 65, Cementing Shallow Water Flow Zones in Deep Water Wells, September 2002, Section 4, addresses site selection for minimizing shallow flows in deepwater wells. Many of the same principles apply to operations for all water depths and well depths and are discussed below in this Annex. • B.1.3 Shallow Hazards Identification and evaluation of hazards through the use of shallow seismic surveys obtained over potential wellsites can aid the operator in proper site selection. If available, shallow seismic data from offset wells or adjacent fields where shallow flows occurred should be used to verify the analysis. If hazards are identified, the risk should be evaluated and mitigation measures taken as appropriate. The operator is cautioned that a shallow hazards analysis is not a conclusive method of prediction, so precautions to minimize the probability of a flow should still be implemented when drilling the shallow portions of the well.lf the decision is made to drill a well in an area that is likely to encounter shallow hazards, drilling the shallow portions of the well with a small diameter pilot hole will make killing the well easier to achieve. B.1.4 Deeper Hazards Potential sources of deeper drilling hazards include abnormal pressure, pressure depleted zones, faults, tectonic stresses, salt flows, and lost circulation. Such hazards can often be identified through seismic interpretation and/or analysis of offset wells or fields. Identification of hazards that could be encountered during drilling operations will aid in proper well planning and in minimizing risk. If available, deep seismic data from offset wells or adjacent fields should also be analyzed to aid in the prediction of flow zones. 68 • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 69 6.2 Planning the Well 6.2.1 Well Conditions After evaluating the well for flow potential and determining the location that minimizes this potential, detailed well planning can begin. An optimum well plan for these conditions incorporates the following features, which are not all inclusive: an understanding of pore pressures, fracture gradients, and required mud weights; — a casing plan that addresses limitations imposed by pore pressure, fracture gradient, wellbore stability, and other operational concerns; — a cementing plan that provides for short- and long-term isolation of potential flow zones; — evaluation of the impact of potential thermal pressure (APB) in subsea wells; selection of drilling fluid(s) that will best control wellbore pressures and enhance cementing success; — a hydraulics plan that provides for adequate wellbore cleaning and control of static and dynamic wellbore pressures; — a barrier design that provides for control of all pressures that may be encountered during the life of the well; — a contingency plan that addresses wellbore instability and unintended gains and losses of fluids; adherence to regulations; — a means to thoroughly and effectively communicate the plan to the personnel that will execute it. 6.2.2 Pore Pressure/Fracture Gradient/Mud Weight In order to drill the well safely, the well planner should understand the anticipated pore pressures, fracture gradients, and mud weights that will be encountered while drilling the well. This information is generally presented in a graph, as shown in Figure B.1. General guidelines for the construction of this graph are as follows. Plot the predicted pore pressure vs depth, expressed as an equivalent mud weight (EMW). It may also be helpful to note lithological information, if it is available. Similarly, plot the predicted fracture gradient (as an EMW) vs depth. Draw a design fracture gradient profile that is offset to the left of the predicted curve by a prescribed amount to roughly account for kick tolerance and the increased ECD during drilling and cementing operations. Typical offset values range from 0.2 ppg to 0.5 ppg. Draw the planned mud weight profile based on the pore pressure and fracture gradient data. In general, the mud weight profile is offset to the right of the pore pressure curve to provide sufficient overbalance for trips (i.e. a trip margin). Typical trip margin values range from 0.3 ppg to 0.5 ppg. Include planned casing diameters and setting depths to clarify wellbore construction features. If mud weight and • LOT information is available from offset wells, include it on the graph for reference. If large disparities exist between the offset well information and the predicted values, further investigation may be warranted. This graph will become the design basis for the well. 70 0 2000 4000 z t 6000 a 0 8000 10000 12000 14000 API RECOMMENDED PRACTICE 65—PART 2 I I 1 I I I f— Mud Weight I f— Fracture Gradient I Design Fracture Gradient ► ' I I Pore Pressure B 16" 11.75" 9.625" 7.625" 8.00 9.00 10,00 11.00 12,00 13.00 14.00 15.00 16.00 17,00 18.00 19.00 0 EMW, ppg Figure 6.1—Casing Shoe Depths with Pore Pressure/Fracture Gradient Graph B.2.3 Casing Plan The appropriate selection of shoe depths and consequently, the required number of strings is critical to the well design. General guidelines are given here for the selection of shoe depths. Local practices, regulatory requirements and experience should also be used to fine-tune this process. Initial shoe depth determinations are made as follows (see Figure B.1). Starting at the mud weight at the well's TD (point A), draw a vertical line upwards until it intersects the design fracture gradient curve (point B). This is the approximate shoe depth of an intermediate casing. — Draw a horizontal line from point B leftwards until it intersects the mud weight curve (point C) and then upward until it intersects the design fracture gradient curve (point D). This represents the approximate shoe depth of the next casing string. — Repeat this process until all shoe depths dictated by mud weight and fracture gradient constraints have been established. After the preliminary shoe depths have been established, an additional check should be made based on kick tolerance. The kick tolerance is the maximum size kick of a specified intensity that can be circulated out of the hole without causing the formation to fracture in the open hole section (often near the shoe). It may be necessary to adjust casing shoe depths to conform to kick tolerance limits. In some higher pressure wells with a small margin between the mud weight and the fracture pressure, the recommended kick tolerance is nearly impossible to achieve. This is particularly true for many wells drilled in the Gulf of Mexico. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 71 There are numerous other factors that affect the design of shoe depths. These factors include the following. — Regulatory Requirements —Applicable local regulations should always be obtained before beginning the design. Hole Stability —This can be a function of mud weight, deviation and stress at the wellbore wall, or it can be chemical. Hole stability problems often exhibit time -dependent behavior, making shoe selection a function of penetration rate. The plastic flowing behavior of salt zones should also be considered. — Differential Sticking —The probability of becoming differentially stuck increases with increasing differential pressure between the wellbore and formation, increasing permeability of the formation, and increasing fluid loss of the drilling fluid (i.e. thicker mud cake). — Shallow Zones with Potential for Flow —Any potential flow zone should be isolated. Zonal Isolation —Shallow fresh water sands should be isolated to prevent contamination. Lost circulation zones should be isolated before a higher -pressure formation is penetrated to avoid downhole crossflow. — Directional Drilling Concerns —A casing string is often run after an angle -building section has been drilled. This avoids drillstring keyseating problems in the curved portion of the wellbore due to the increased normal force between the wall and the drillpipe while drilling deeper sections of the well. — Uncertainty in Predicted Formation Properties —Exploration wells often require additional strings to compensate for the uncertainty in the pore pressure and fracture gradient predictions. • — Hole and Pipe Diameters —The selection of pipe diameters has the largest impact on well costs in both design base and detailed casing design. In general, hole and pipe diameters should be designed to be the smallest possible, which meet all design requirements, well objectives, safety, and environmental requirements. In exploratory wells, hole diameters may be larger to allow for contingency casing string(s). The final hole or casing diameter is generally determined by evaluation, completion, and production requirements. Because of this, casing sizes should be determined from the inside outward. Hole and casing diameters are based on the following requirements. — Drilling —Bit diameter (hole size) should be minimized to aid in maintaining the required "deflection point" when directionally drilling, available downhole equipment, rig specifications, and available BOP equipment. — Cementing —See 4.2 and 4.5, and B.2.4 for more information. — Production —Production equipment requirements including tubing, subsurface safety valve, submersible pump and gas lift mandrel size, completion requirements (e.g. gravel packing), and weighing the benefits of increased performance of larger tubing against the higher cost of larger casing over the life of the well. — Evaluation -logging requirements and tool diameters. B.2.4 Cementing Plan Short- and long-term isolation of potential flow zones requires proper cementing planning and execution. Listed below are several aspects of well planning that may affect the success of primary cementing operations. These items are covered in more detail in Section 4: . — hole size and shape (washouts and annular dimension), selection of mud for filter cake and rheological properties, 72 API RECOMMENDED PRACTICE 65-PART 2 — mud conditioning, — spacers, — cement slurry design, — pump rates, — centralization, — testing/evaluation plan. B.2.5 Drilling Fluids Plan The drilling fluid is a key factor in the isolation of potential flow zones because of its pressure -control function and because it can affect the success of any cementing operation. Key drilling fluid considerations that relate to cementing success include: — mud density or mud weight (MW), — mud type, — filter cake properties, • — rheology and gel strength properties, fluid stability, — effects of drilling fluid on wellbore stability. These items are covered in more detail in Section 6. B.2.6 Wellbore Hydraulics B.2.6.1 (ECD) Management A plan should be developed to monitor and control static and dynamic fluid pressures of the mud column such that ECD is maintained within appropriate limits. Static fluid pressure should be sufficient to contain maximum open hole formation pressure and minimize wellbore stability problems, while dynamic fluid pressure should be held below the minimum breakdown (fracturing) pressure of any exposed formation. Hole size, casing size, BHA and drillpipe size selection should be balanced with the fluid properties and surface equipment ratings to ensure ECD can be maintained within the desired range. Offset well files should be reviewed for indications of lost circulation, stuck pipe, significant borehole washout, etc., and the ECD management plan should be modified to mitigate these problems. ECD increase in high -angle and horizontal wellbore sections should be addressed in the plan, as the formation fracture gradient will remain constant in the horizontal section of the well while fluid friction pressure will increase. Numerous well design parameters can impact ECD including the use of casing strings with increased annular clearances, use of liners rather than full casing strings, selecting fluids that reduce frictional losses, expandable tubulars to preserve hole size, and controlling ROP to avoid overloading the annulus with cuttings. Critical circulating and swab pressures should be documented in the plan. A wellbore hydraulics simulator should be used on each well. ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 73 B.2.6.2 Wellbore Cleaning Cuttings transport to the surface is primarily controlled by annular velocity and fluid rheology, so care should be taken when selecting components that impact these parameters. Surface drilling equipment (mud pumps, flow lines, and shakers) should be sized to accommodate the maximum rate of cuttings generated. Hole deviation should be considered when designing higher annular velocities for proper hole cleaning. Ensure chemical compatibility of the formation and the mud system to avoid swelling problems. The bit nozzle selection should be based on optimizing ROP, bit cleaning, and annular velocity for transport of solids to the surface. It is recommended that a wellbore hydraulics/hole cleaning simulation model be run on each well to determine minimum and maximum flow rates. Maximum pipe -tripping speed should be controlled to avoid creation of excess swab/surge pressure during hole cleaning operations. Wells drilled from floating vessels should consider the use of a booster line when high solids loading is expected in the riser. Conventional hole cleaning tactics may have to be supplemented with hole cleaning pills under certain conditions. Viscous pills and high weight pills can be effective at removing cuttings. However, the use of pills should be minimized where possible, as they can contaminate the mud system. B.2.7 Barrier Design The operational goal of any well design is to provide sufficient barriers between formations and between those formations and the surface. A well's barrier plan should include maintaining well control via hydrostatic pressure from fluids, selection and use of well control equipment, and the placement of cement or other mechanical barriers in the well. The well center design (i.e. wellhead, BOP equipment, riser, etc.) should include a minimum of two barriers available during any operation to prevent uncontrolled flow from the well to the atmosphere. The barrier design should . incorporate the following elements: — ability to withstand the maximum anticipated wellbore pressure, — ability to be tested for function and leaks, failure of a single barrier will not result in uncontrolled flow from the well, the operating environment is within the design specifications of the barrier element. In addition, at least one of the barriers should have the capability to do the following. Shear any device that passes through the barrier and seal the wellbore after shearing. If this is not possible, an alternative pressure control plan should be created. Seal the wellbore with any size device penetrating the well barrier. If this is not possible, an alternative pressure control plan should be created. Evaluation of the viability of each barrier should be considered in the planning process. Plans should address well control issues each time a barrier is removed or replaced. For example, after a cement job, the BOP system is typically removed to install wellhead components. At these times, the barriers in the well have changed from fluids and the BOP stack to fluids and cement. The plan should address when the cement properties are adequate to make that change. Plans for testing of well barriers should be part of each well design. Barrier plans should address pressure integrity through pressure testing, but may also require negative testing of a liner top prior to changing out the wellbore fluid. If drilling is planned for an extended period of time (> 30 days), potential casing wear issues should be reviewed, and casing size/tool joint facing material should be selected such that wear will not impair the casing's ability to withstand all potential loads. 74 B.2.8 Deepwater Barrier Planning API RECOMMENDED PRACTICE 65-PART 2 The column of fluid in the riser does not act as a well barrier when the marine riser has been disconnected. Planned or accidental disconnect of the marine riser should be addressed in the well center plan. Operators may be able to maintain a drilling fluid density that will provide an overbalance condition with the marine riser disconnected. If this is not possible, a weighted fluid may be displaced into a portion of the wellbore, so that zones with flow potential remain under control in the absence of the hydrostatic pressure from fluid in the marine riser. Deepwater operating plans should also address the following issues: — detailed riser analysis should be performed to verify that the riser can withstand all anticipated environmental (weather, current, and sea state) and operating loads; — the riser disconnect system should be analyzed to verify the ability to safely disconnect under all anticipated loads; — riser stress should be measured or calculated to determine an optimum rig position to minimize the effects of static and dynamic loads. B.2.9 Contingency Planning 13.2.9.1 General The potential for instability caused by unintended transfers of fluids or solids between the wellbore and the formation should be identified in pre -drill analyses. Contingency plans should be developed to specify the procedures, equipment, and personnel needed to avoid adverse situations or to suppress incipient dangers before they become unmanageable. Contingency plans should consider events that fall into three categories: fluid influxes, lost circulation, and formation failures such as breakouts and packoffs. 6.2.9.2 Well Control Planning for Fluid Influxes Kicks —the following equipment and supplies for contending with kicks should be available at the rig site: adequate supplies of heavy mud —these should be kept ready for mixing in the reserve pit; — a diverter when shallow formation flow hazards exist such as high pressure shallow gas or water zones; — properly selected and well -maintained well control equipment such as blowout preventers (BOPs), chokes, and degassers. Well control procedures vary depending upon whether surface or subsea BOPs are employed and whether a kick occurs while tripping, drilling, or the bit is out of the hole; however, in general, such procedures include: — the use of kill mud and circulating out the kick, — bullheading the kick back into the formation, — diverting shallow gas, — temporarily shutting in the well, 0 — plugging the borehole with barite or cement plugs leading to partial or complete abandonment of the well. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 75 13.2.9.3 Shallow Water Flows Shallow water flows are best managed by drilling the interval with weighted fluid. For cementing of shallow flow zones, specialized cements are recommended as detailed in section 4.7 and in API RP 65—Part 1. More information on controlling and cementing shallow water flow zones can be found in API RP 65—Part 1, Cementing Shallow Water Flow Zones in Deep Water Wells. B.2.9.4 Planning for Lost Circulation Control Methods for avoiding or curing lost circulation during drilling can be found in C.2 and C.3, while those for handling lost circulation during casing and cementing operations are described in 4.7 and 4.8. Procedures for managing wellbore breathing or ballooning should also be considered. Wellbore breathing can be an indication of imminent lost circulation. If breathing is observed, the following responses should be considered. — Review system hydraulics to determine if it is possible to reduce ECD. Consider reducing the mud weight, if possible. — Monitor flowback while making connections. Record the volume and duration of flow. — Do not weight up and risk loss of returns. — Apply LCM pill. — When a kick and breathing both occur, it may be time to set casing. 0 13.2.9.5 Formation Failure Procedures for avoiding or managing formation failure vary depending upon the type of formation, the nature of the instability, and the availability of resources. In general, the following practices should be observed: — maintain the ECD within planned boundaries (see B.2.6); use an appropriate mud type that provides adequate filter cake and cuttings transport, and inhibits chemical reactions with the formation; — avoid surging or swabbing the formation and reduce tripping speeds when the BHA is opposite problem formations; — minimize the exposure time in areas where rock deformation or failure is time -dependent (e.g. in salt); — ensure good hole cleaning (see B.2.6). In the event of a packoff, the following measures should be applied in the order listed: — turn off the pumps and bleed down the standpipe pressure; — apply maximum make-up torque; — work the drillstring up and down; — increase the standpipe pressure and continue to apply torque and work the pipe; — as a last resort, commence jarring in the direction opposite to the last pipe movement. 1� u 9 76 API RECOMMENDED PRACTICE 65-PART 2 B.2.10 Regulatory Issues One component of proper well planning includes appropriate regulatory review. Typically, the regulatory agency with jurisdiction for the well will need to review the well plan before operations begin. Well plan submittal documents tend to have the following features in common: — a description of drilling objectives, — planned casing and cementing programs, — drilling fluid program, equipment testing policies and procedures, borehole evaluation and directional survey programs, — estimates of pore pressures and fracture gradient. Depending on the type of regulatory system in effect, the agency may or may not approve the well plan in its entirety, or it may require certain changes to the plan to meet regulatory requirements. B.2.11 Communications Plan A key feature of good well design is effective communication of the plan to the personnel that will execute that plan. The well design should be communicated through a written plan and through personnel meetings. For complicated wells, holding a meeting to "drill the well on paper" can often highlight areas of risk and concern, and gives an opportunity for all parties to understand their role in executing the well program. A discussion of human factors, required training and experience of personnel should be highlighted. Pre -spud meetings should take the final well plan and highlight any areas of concern. The meeting should review the full well plan in detail, highlight and review safety issues with the personnel, and address topics related to annular flow prevention. The prevention of annular flow does not rest solely with the cementing operation and well control equipment. It is a process that involves wellhead equipment, directional control, wellbore quality, drilling fluid management and cementing operations. Annex C (informative) Drilling the Well CA General Practices While Drilling The following practices should help maintain efficient drilling results and provide hole quality conditions suitable for primary cementing: — using a drilling fluid of sufficient density to contain formation fluids; — use of high viscosity sweeps to reduce potential for annular pack off or excessive gumbo deposition; — controlling mud losses using LCM as needed; — minimizing static gelled mud with flat gel strength mud rheology; — preventing excessive mud filter cake buildup with low fluid loss muds; — preventing balling on the BHA due to gumbo; — rotating pipe while breaking circulation to reduce lost circulation potential on connections; — while on diverter, the rig should pump out of the open hole and assess trip fill by monitoring each stand while circulating through the trip tank; — controlling rate of penetration (ROP) to prevent overloading the wellbore with cuttings and minimizing the opportunity for gumbo accumulation; — monitoring mud gas content and volume to verify flow potential. C.2 Monitoring and Maintaining Wellbore Stability Having a stable wellbore prior to, during, and after the cement job is crucial to cement job success. If losses or gains occur during a cementing operation the possibility of obtaining a successful cement job is greatly diminished. Corrective action should be taken to stabilize the wellbore prior to the cementing operation. Certain corrective measures are best applied prior to running the casing or liner string into the well. The following indicators are used to identify potential flows and losses, contributing to wellbore instability: — changes in pit volume —monitor trend; — changes in flow rate —monitor trend; — changes in pump pressure; — ROP—monitor trend; — torque and drag; — changes in weight on bit (WOB)—monitor trend; pressure while drilling (PWD) data; 77 78 — ECD variations; API RECOMMENDED PRACTICE 65—PART 2 — fracture gradient via shoe and open hole LOT data; — cuttings size and shape; — variation in "d" and "dxc" exponent; — abrupt lithology changes; — returned mud gas (background, connection, and trip); — flowline temperature; — mud properties -look for mud cut density, change in salinity, oil in retort, etc.; — shale density; formation changes from LWD/MWD data; — presence of geologic hazards: — fractures, — faults, — unconformities. Many of these indicators are precursors to wellbore losses or kicks which can result in an unstable wellbore. C.3 Curing and Preventing Lost Circulation C.3.1 General Detailed well planning and accurate hydraulic modelling is extremely important in minimizing lost circulation. Lost circulation is one of the most common and expensive problems that are encountered while drilling or while running casing. Loss of circulation can lead to loss of well control and a multitude of associated problems. The financial consideration is of concern with any type of drilling fluid but the importance is the greatest when using NAF. Loss of circulation can lead to well bore instability and well control problems that can drastically affect the outcome of drilling and cementing of the well. See A.10 for more information. Loss of circulation occurs when either one of the following conditions is met: — the pressure exerted by the mud column either while static or during circulation (surge is considered as circulating) should exceed the fracture pressure of one or more of the formations exposed in the borehole; — the porosity and permeability of the formation or space within the fissure or pre-existing "natural' fracture is large enough to permit the passage of whole mud thus preventing the sealing effect of the filter cake. Drilling fluid losses can be categorized as two types: natural and induced. • • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 79 C.3.2 Natural Losses Examples of natural losses include the following. Loss Through Rock Permeability —For whole mud to be lost, the formation openings should be larger than the largest particles contained in the drilling fluid. These types of formations are usually characterized by seepage losses occurring in highly porous intervals usually encountered at shallow depths. Typically these formations are sands and gravels. — Formations containing natural fractures and leaking faults. — Cavernous and vugular porosity —Formations such as limestone or dolomites in which voids have been dissolved by ground water. C.3.3 Induced Losses Losses due to a mechanical disturbance of the wellbore can create fractures in the formation. The hydrostatic pressure thus created in the wellbore exceeds the formation break -down pressure and mechanically fractures the rock. These types of losses are different than what is seen in natural fractures since the fracture network is not interconnected. Some of the causes of induced fractures are affected by the following: — fluid density and/or ECD, — additional hydrostatic pressure due to length of riser, 0 — insufficient hole cleaning, — excessive ROP with solids loading of mud column increasing MW, — high pump rates, drilling fluid rheological properties, tripping speed, — wellbore geometry, — restricted annulus from packoffs or BHA balling. C.3.4 Loss Rate Categories Losses of mud to the formation have been arbitrarily defined in the following categories: — seepage losses from 1 to 20 bbl/hr; — partial losses from 20 to 50 bbl/hr; — severe losses greater than 50 bbl/hr but the hole will remain full with the pumps off; — complete losses, no returns while pumping or the hole will not remain full with the pumps off. • • 80 API RECOMMENDED PRACTICE 65-PART 2 C.3.5 Preventing Losses C.3.5.1 Drilling Fluid Properties Drilling fluid properties can be optimized to prevent losses using the following: — proper solids control management, — keeping the fluid density as low as possible, — maintaining gel strengths and yield point at the lowest levels that will effectively clean the hole and effectively suspend barite and cuttings, — preventing excessive filter cake build-up by controlling fluid loss, — using hydraulic prediction software to predict ECD and determine optimum fluid properties. C.3.5.2 Minimize Surge Pressures Surge pressures can be minimized by: — staging in the hole to prevent excessive circulating pressures; — rotating the pipe to mechanically shear the mud reducing gel strength before turning on the pumps, and bringing . the pumps up slowly; — monitoring and controlling pipe running speeds; — using available hydraulics modeling software for predicting surge pressures; — calculating annular flow and running casing slowly enough to avoid high pressure (speed of lowering each joint, not the average speed). C.3.5.3 Downhole Equipment The following downhole equipment practices will help reduce ECD to limit losses: — using downhole pressure measurements to monitor and manage ECDs in real time, — using BHA components with maximum annular flow paths across the tools, — installing auto -fill and various enhanced flow by-pass equipment to minimize surges while running casing, — using downhole tools that allow for high concentrations of LCM. C.3.6 Identifying the Loss Zone Quickly identifying where the loss zone is located will greatly enhance the performance of the treatment used to counter the lost circulation. Temperature logs, spinner surveys, noise logs, LWD data analysis and stress modeling, connection flow monitoring analysis, lost circulation computer model simulations, and offset well mud loss data are a few of the techniques used to identify where the suspected loss zone may be located. If a NAF is used, the suspected loss zone could be identified during a short trip by very high resistivity readings in an otherwise non -productive zone. • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 81 C.3.7 Lost Circulation Materials and Systems C.3.7.1 General There are a wide variety of lost circulation materials available to deal with the most severe types of lost circulation. There is no universal treatment available to cure all types of lost circulation. LCM can range from fine to coarse particulate materials, fibers, cements, reactant pills and acid soluble particulates. The type of material should be matched with the severity of the lost circulation encountered. C.3.7.2 Seepage Losses The most common type of lost circulation materials for seepage losses are the fine cellulosic fibers and fine granular types of additives. The most commonly used granular material is calcium carbonate. Another widely used technique is to pump the fine seepage loss additives as a sweep while drilling the seepage loss zone. C.3.7.3 Partial Losses The most commonly used materials for this type of loss circulation are granular- and flake -type products that have particles sizes larger than those used to deal with seepage losses. These can include mica, nut shells, and medium to coarse calcium carbonate, graphitic materials and coarse cellulosic fibers. These additives can be added to the mud system as a continuous treatment or can be spotted as a sweep across the suspected loss zone. C.3.7.4 Severe Losses Materials commonly used for severe losses are granular and flake type products that have larger particle sizes than those used to deal with partial losses. As the severity of the loss becomes greater than the preceding two types of losses, coarser sizes of the same additives should be used for bridging, but some of the finer particles can be included. These additives can be added to the mud system as a continuous treatment or they can be spotted as a sweep across the suspected loss zone. C.3.7.5 Complete of Total Losses The types of additives and procedures used to deal with total losses are generally different than those required for the preceding types of lost circulation. These types of losses generally occur in formations with leakoff flow paths larger than the diameter of most bridging particles. Large fracture openings and vugs usually account for these massive losses. These openings are not effectively sealed with the cellulosic and granular type of products described above. Reactive pills and agglomerating -type LCM materials are used under these circumstances. Some of these include: — high filtration squeezes allowing for rapid loss of the carrier fluid resulting in a solid plug forming in the formation opening; — hydration type systems where a very active material such as powdered clay or mixtures of clays and polymers in an inert carrier reacts with the drilling fluid to form a rubbery type of plug; — chemical systems where special resins or polymers and catalysts react to form a semi -solid plug; — mixtures of the above systems with cement to create highly viscous and hard setting plugs; — special, highly thixotropic cement slurries squeezed into the zone or left in the wellbore as a plug; 0 — large volumes of these materials for cavernous loss zones or special squeeze cements such as foam cement; • 82 API RECOMMENDED PRACTICE 65-PART 2 — silicate -base gels with and without cement; — fibrous cement systems that form a bridge across the thief zone. C.3.8 Planning and Operations Considerations The following outline summarizes, in general terms, the data requirements and steps involved to plan a well in which lost circulation is a possibility. a) Pre -well planning for all phases. 1) Drilling.- i) pore pressures and fracture gradients; ii) fluid selection—NAF vs water based mud (WBM); iii) optimizing flow properties; iv) ECD control, annular pressure measurements; v) controlled ROP and hole cleaning; vi) caliper logs; • vii) lost circulation, near-wellbore stress, and ECD computer modeling; viii) treatment plan to prevent or mitigate losses. 2) Running casing and liners: i) swab and surge pressure modeling; ii) insure the hole is clean and free of cuttings; iii) reduced mud weight and rheology; iv) casing hardware selection; v) pre -treat the drilling fluids to reduce pressures; vi) breaking circulation. 3) Cementing: i) ECD modeling; ii) ensure losses are cured before cementing; iii) utilize good cementing practices (see Section 6); • iv) cement slurry design; v) LCM in the cement slurries; • ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 83 vi) spacer considerations —flushes, spacer design (hydraulics); vii) use proper cement densities and cement volumes. b) Operational considerations. 1) Drilling: i) pre -treat mud with various particle size distribution (PSD) materials; ii) modify pre-treatment as required depending on wellbore reaction; iii) app►y planned treatments as needed to control losses. 2) Running casing: i) if possible cure the lost circulation prior to running casing; ii) spot LCM in the open hole prior to running casing. 3) Lost circulation and near-wellbore stress computer modeling: i) optimize planned treatments based on actual conditions. 0 • • is • Annex D (informative) Cementing Matrix and Instructions D.1 Matrix Instructions This matrix is to be used to evaluate the potential impact of elements of the cementing process on its success. The sheet should be completed by the operator during the planning of the well to highlight areas needing improvement. At the conclusion of each string on which it is used, the scores for each parameter should be evaluated again and used as a post job evaluation. The sheet can be printed at each of these stages and placed in the well file. The scores, both by major category and the total can be compiled in a database and, with evaluation of flow, used for process improvement. Explanation of Terms Max Points The maximum number of points to be assigned for the parameter if the recommended criteria are met completely. Penalty Points Points may be deducted if the cement job execution or the placement of a mechanical barrier does not meet the design criteria. Plan Score The score for the parameter based on the degree to which the parameter is met in the design of the well. Performance Score The score for the parameter based on the degree to which the parameter was met when the operation was performed on the well. Actual Value The actual value (not score) of the parameter when the operation was performed. For instance, if the fluid loss of the drilling fluid is 12, enter 12 for the "Actual Value" while the "Performance Score" is 2. Use of Matrix to Assess Areas for Improvement Each of the critical parameter categories can be evaluated by comparing the Total Score against the Individual Parameter possible score (Max Points) for that category. If the earned score is less than half the possible score, Totals consideration could be given to adjusting parameters to increase the score. For categories with penalty points, if any points are deducted then actions should be taken to correct the problem. If the earned sheet total is low, consideration could be given to increasing the score by improving Sheet Total individual parameters or improving upon execution. The greater the risk and severity of annular flow, the more important it is to increase the score. Criteria Directions Risk Assessment Site Evaluation Assign 5 points if the site has been evaluated for the presence of hazards by an appropriate process. No points are assigned if no assessment is done. Assess Flow Assign 10 points if the interval cemented for this specific job has been evaluated for flow potential by an Potential appropriate process and preventive measures taken. No points are assigned if no assessment is done or preventive measures are not taken. Pre -job Awareness Assign 10 points if all criterion is met or 0 if it is not. Assign 10 points if the mud and cementing hydraulics program for this specific open hole interval has Lost Circulation Risk been designed by an appropriate process to allow sufficient operating window to prevent lost circulation. No points are assigned if no assessment is done or design/preventive measures are not taken as appropriate. 5 points are still allowed if lost circulation is unexpected and can't be remediated. 84 4� u LJ ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 85 Criteria Directions Critical Drilling Fluid Parameters Rheology Assign 4 points if rheological properties and static gel strength are conducive to cuttings removal and suspension and proper management of ECD. Density Assign 4 points if criterion is met or 0 if it is not. Fluid Loss Assign 4 points if criterion is met or 0 if it is not. Criteria Directions Critical Well Parameters Hole Diameter Assign 4 points if criterion is met, or scale points if it is not. Hole diameter must allow space to run centralizers adequate to provide standoff needed to achieve mud removal for zonal isolation. Gauge Hole Assign 4 points if hole size is no more than ten percent greater diameter than bit across zones having potential for flow and those immediately adjacent. Assign 4 points if dogleg severity across zones requiring isolation is sufficiently low to allow centralization Deviation, Dogleg adequate for mud removal for zonal isolation. Inability to run centralizers past a shallower depth due to Severity dogleg severity and wellbore tortuosity due to bit walk may be a factor. No points are assigned if minimum centralization cannot be achieved. Top of Cement Assign 6 points if all potential flow zones are covered by cement. If lithology and formation flow potential are unknown, TOC should be inside previous casing for criteria to be met. Trapped Annular Assign 4 points if an assessment of risk of trapped annular pressure in designing TOC has been made Pressure and mitigated. Mitigation may include surface venting. No Points given if criterion not met. Assign 6 points if the well is in overbalance condition at all times during the conditioning and cementing Well Control based on computer simulation and no flow occurs during either circulation or static flow checks. If underbalance or flow occurs at any point, assign no points. Mechanical Barrier Assign 4 points if the use of mechanical barriers (e.g. liner top packers, ECPs) has been evaluated and appropriate installation made Rathole Assign 2 points if criterion met or 0 if it is not. Criteria Directions Critical Operational Parameters Lost Circulation Assign all points if full returns were observed and if computer simulations indicated that fracturing pressure is not exceeded during conditioning and Cementing. Running Casing Assign points if casing is run with stops to break circulation and condition mud and running speed is sufficiently low that surge pressure will not cause losses. BOP & Diverter Testing Assign 4 points if all criterion is met or 0 if it is not. Annular Monitoring Preparation Assign 5 points if all criterion is met or 0 if it is not. To minimize drilling fluid gel strength development during static time, pressure test lines before beginning Static Time conditioning. Assign all points if the static time is < 5 minutes total from start of conditioning until end of cementing. No points are earned if the time is > 15 minutes. End of Inner String Assign 4 points if criterion met, subtract 1 point for each additional 20 ft. 86 API RECOMMENDED PRACTICE 65-PART 2 Criteria Directions Critical Mud Removal Parameters Mixing and Full points are assigned if the rate at which fluids are circulated during cementing (when fluids are being Placement Rate displaced in the annulus) is designed to meet specific engineered mud removal criteria using computer simulations. Otherwise, no points are earned. All points are earned if centralization is optimized using a placement simulator and the caliper log for mud Centralization removal criteria through zones with flow potential. Award 3 points if centralizers are run without regard to placement simulators. Otherwise, none are earned. Assign all 5 points if the spacer is designed so that density never allows the annular pressure to fall below pore pressure of the potential flow zone AND volume is sufficient for 1000 feet of annulus or 10-minute Spacer contact time. Subtract one point for each 100 ft or one minute of contact time for which the volume is deficient between 1000 and 500 ft. No points awarded if spacer is less than 500 annular feet. No points are awarded if spacer density compromises hydrostatic control at any point during the job. All 5 points are earned if compatibility of spacer with mud and cement has been tested and found to be Fluid Compatibility compatible AND spacer wettability testing is performed for non -aqueous muds. Otherwise none are earned. Compatibility should include evaluation based on rheological and wettability testing (for non - aqueous fluids) according to API RP1013, as well as visual observations. Scale points based on volume circulated before cementing. 4 = greater than one total hole volume (casing Circulation Volume + annulus) and mud properties (of returned mud) are fully optimized, 3 = one hole volume only with full returns, 2 = annular volume only with full returns, 1 = sufficient only to establish returns, 0 = no circulation prior to pumping the cement job. Rheology Assign points if drilling fluid properties have been designed to be conducive to cementing operations, including both static and dynamic fluid properties. Float Equipment Give 4 points if float equipment is run that provides minimum of 2 float valves, 2 points if only one valve. Wiper Plugs Give 4 points if both top and bottom wiper plugs are used, 5 points if bottom wiper plug is run between the spacer and cement. 1 point is awarded if only a top plug is used. Pipe Movement All 8 points are earned if pipe is moved during conditioning and cementing, 6 points if only during conditioning and not during cement placement. Otherwise, none are earned. Give 4 points if some means of annular tracer is employed either during conditioning or cementing Tracers Employed operation. Tracer may be visual (dye, beads, etc.) or chemical (pH indicator). No points are earned otherwise. 40 • • r� ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 87 Criteria Directions Critical Cement Slurry Parameters Temperature for All points are earned if temperature schedules have been established based on measurements combined Cement Testing with computer modeling and/or offset well data. No points are earned otherwise. Slurry Design All points are earned if the lead slurry is designed so that the gel strength development and thickening (lead vs tail slurry) time are longer than for the tail slurry. Specification includes applicable (batch) mixing and placement times. Points are given if the CSGS period of the slurry meets criteria. If CSGS period is greater than 1 hour then no points are awarded. If CSGS period is less than 45 minutes then 4 points are awarded. This CSGS Period is defined as the time required for the cement to progress from the "critical static gel strength" to a static gel strength of 500 Ibf/100 ft2. The CSGS is the gel strength of the cement that results in hydrostatic decay producing an exactly balanced condition in the well. The lead slurry should not approach its CSGS prior to the tail slurry having completed its CSGS Period. CSGS can be computed by: CSGS = (0BP)(300)(L/De ff) Slurry Design where (static gel strength) OBP is the overbalance pressure (psi); 300 is the conversion factor; L is the length of the cement column (ft), Deff is the effective diameter (in.) = DOH — De; De is the diameter of the casing (in.); DO,, is the diameter of the open hole (in.). Slurry Design Assign all points if the rheology of the slurries are designed to meet mud removal criteria and ECD limits (rheology) are not exceeded in computer modeling. Slurry Design All points are assigned if slurry placed across potential flow zones has controlled fluid loss appropriate for (fluid loss) the flow potential. Otherwise, no points assigned. Slurry Design All points are earned if density meets requirements for maintaining wellbore pressure between pore and (density) fracturing conditions and appropriate adjustments have been made in the event any kicks occurred during drilling. Slurry Design (stability) All points are given if free fluid, sedimentation and foam stability (when cement is foamed) meet criteria. Slurry Design All points are given if slurries are determined to be compatible with one another. Compatibility criteria to (compatibility) be established between vendor and operator on an individual basis. Slurry Design (mechanical All points are given if the cement has been designed to meet specific criteria of mechanical properties as properties) needs are indicated by future well operations, computer modeling, or offset experience. Slurry Design All points are earned if tests of samples of the blended cement according to vendor's or operator's quality (blend verification) plan verify critical performance properties of the cement. • 0 0 88 API RECOMMENDED PRACTICE 65—PART 2 Criteria IDirections Job Execution Problems (Penalty Points) For this section, points are deducted (i.e. malice points) for deficiencies in job execution. If 100 % of the cement slurry was mixed within ± 0.2 lb/gal then no points are deducted. If more than 80 % of the slurry is Density Control not mixed within ± 0.2 lb/gal then 10 points are deducted. The number of malice points are scaled down based upon the percent volume of the slurry mixed outside of ± 0.2 lb/gal between 100 % and 80 % of the job (e.g. 90 % compliance deduct 5 points). Do not include transition between lead and tail, or a small volume while bringing the first volume up to density. Unplanned One point is deducted for each unplanned minute of shutdown encountered during the job. The maximum Shutdowns deduction is 5 points. No points are deducted if there are no unplanned shutdowns during the job. Special Blending All points are deducted if specialty blends are not prepared at the bulk plant in accordance with the Mixing suppliers established guidelines. No points are deducted otherwise. Liquid Additive All points are deducted if the liquid additive system is not calibrated or if it does not deliver liquid additives System at the proper ratio during the job. No point are deducted otherwise. Float Equipment Deduct all points if the float equipment does not hold and pressure is left on casing while WOC. No points are deducted if the floats hold and no pressure is held on the casing during WOC. Nitrogen Injection Applicable only when foamed systems are in use - all points are deducted if nitrogen injection does not (foamed cement) use automated process controlled equipment. No points are deducted if an automated system is used on the job. Applicable only when foamed systems are in use - all points are deducted if either nitrogen or foaming Foamer and Nitrogen agent is not pumped within five percent of design. No points are deducted if both criteria met. Specific at Proper Ratio applications may require less margin and the matrix threshold value should be adjusted accordingly for such cases. Criteria Directions Mechanical Barrier Considerations Applicability All points awarded if well design considers need for mechanical barriers. No points otherwise. For surface barrier such as those specified in 3.5 award all 20 points. For external packers (e.g. liner top Type of Barrier packers) or other such devices located within the previous casing, award 20 points. For external packers or other such devices located in the openhole and in competent formation above any potential flow zones, award 10 points. Criteria IDirections Mechanical Barrier Problems (Penalty Points) Set in Appropriate Deduct all points if annular mechanical barrier is not set in an appropriate location such as inside the Location previous casing or otherwise below planned abandonment depth. No points deducted otherwise. Cementing Program Designed to All 5 points deducted if the cement slurry and pumping procedures are not effectively coordinated with the Accommodate operational considerations of the selected annular mechanical barrier. Overall effectiveness depends on Operation good communications. Successful All points deducted if successful integrity of mechanical barrier cannot be ascertained by methods Indicator(s) appropriate to the tools. No points deducted otherwise. • • is ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 89 Criteria Directions Post Cementing Parameters Annular Monitoring All points are earned if annulus s monitored (either visually or with positive pressure indication) and is kept full duringWOC time. No points otherwise. WOC Before Nippling All points are given if WOC criteria are established and used as shown in the WOC Decision Tree (see Down 3.7). None are given otherwise. Award 4 points if casing is pressure tested (within pressure limitations of plugs, float equipment, cement Pressure Test Casing head, and any other associated equipment) when plugs are landed and before cement slurry enters critical gel strength period. No points otherwise. Annular Top Out Procedure Award 4 points if Annular Top Out Procedure is performed based on requirements and conditions Cement Top Award 4 points if top of cement is placed as designed based upon volumetric returns or verified with wireline measurement. No points awarded otherwise. • • API RECOMMENDED PRACTICE 65—PART 2 D.2 Cementing Matrix Key Cementing Parameters for Zonal Isolation Performance Actual Parameter Recommended Criteria Max Points Plan Score Score Parameter Value Risk Assessment & Awareness Training Site Evaluation Site is evaluated for flow hazards. 5 Assess Flow Hole Interval is evaluated for flow 10 Potential potential. Annular flow risk issues discussed in Pre -Job Awareness pre -spud AND pre -cement job safety 10 meetings. Lost Circulation Risk ECD window adequate for successful 10 drilling and cementing program. Section Total 1 35 0 1 0 0 Critical Drilling Fluid Parameters Yield point and static gel strength Rheology conducive to cuttings suspension and 4 removal and ECD management. Density Appropriate for well control —prevention 4 of both kicks and losses. Fluid Loss Adequate to provide a thin, compact 4 filter cake. Section Total 12 0 0 0 Critical Well Parameters Hole Diameter Hole diameter sufficient to run adequate 4 centralization. Gauge Hole Diameter no more than 10 % over bit. 4 Deviation/Dogleg Trajectory allows running casing & 4 Severity adequate centralization. Top of Cement Adequate TOC above shallowest 6 potential flow zone. Trapped Annular Assess risk of trapped annular pressure 4 Pressure in designing TOC. There is no flow, no losses (well stable) Well Control before or during conditioning and 6 cementing. Rathole length (below casing shoe) is Rathole minimized, filled with high density mud, 2 or appropriate barrier capable of supporting cement. Section Total 30 0 0 0 Critical Operational Parameters Full returns are maintained and fracture Lost Circulation initiation pressure is not exceeded at 4 any time during conditioning and cementing. U 0 ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 91 Critical Operational Parameters Casing is run in such a way as to Running Casing minimize pressure surges that can 4 cause losses. BOP and Diverter Testing BOP and diverters function -tested. 4 Annular monitoring Annular monitoring plan and equipment 4 preparation in place. Non -circulating time is < 5 minutes from Static Time start of mud circulation until completion 4 of cementing operation. Pressure test lines before conditioning. End of Inner -string (inner -string Within 80 ft of upper -most float valve if 4 cementing only) not a stab -in job. Section Total 1 24 1 0 1 0 1 0 Critical Mud Removal Parameters Circulation rate in annulus before and during cementing meets mud removal Mixing and criteria established by computer 6 Placement Rate simulation and does not exceed the maximum rate that was achieved during pre -job circulation. Centralization is optimized for mud Centralization removal through critical zones and 10 centralizers are run according to engineered design. Spacer Optimize density, rheology, and volume. 5 Mud: Spacer and Spacer: Lead Slurry Fluid Compatibility are compatible. Preferentially water- 5 wetting for sections drilled with NAF. Sufficient to obtain desired fluid Circulation Volume properties. Minimum of one hole 4 volume. Rheology and static gel strength Mud Rheology conducive to good mud removal and 5 ECD control. Float Equipment Floats run to prevent flow back into 4 casing. Wiper Plugs Top and bottom plug used. Bottom plug 5 run between spacer and cement. Pipe Movement Pipe is moved to enhance mud 8 displacement. Tracers Employed Annular tracer method employed (see 4 comment). Section Total 56 0 0 0 • 0 92 API RECOMMENDED PRACTICE 65—PART 2 Critical Cement Slurry Parameters Realistic test temperatures established Temperature for by measurement, local correlations, 6 Cement Testing thermal modeling software, and/or other accepted industry methods. Lead: Tail setting Lead slurry has longer thickening time Profiles and slower gel strength development 4 than tail slurry. Gel strength development (Critical Gel Gel Strength Strength Period) meets time 4 requirements (see comment). Rheology Rheology appropriate for mud removal 4 criteria and ECD limits Fluid Loss Fluid loss control is appropriate for the 4 flow potential (see comment) Density Cement density appropriate for well 4 conditions. Stability Slurry stability (free fluid, sedimentation 4 and foam stability meet criteria). Compatibility Lead and tail slurry are compatible with 4 one another. Mechanical Cement mechanical parameters 4 Parameters appropriate for anticipated stresses. Cement blend According to quality plan (vendor's or 4 verification tests operator's). Section Total 42 0 0 0 Job Execution Problems (Penalty Points) Density Control Density not maintained at ± 0.2 lb/gal of —10 design. Unplanned Unplanned shutdowns > 5 minutes (e.g. Shutdowns bulk delivery problems, fluid delivery —5 problems, equipment malfunction, etc.). Special Blend Mixing Opecial blend procedures not adhered Liquid Additive LA system not calibrated or not —4 System delivering accurately. Float Equipment Float equipment does not hold and —10 Holding pressure is left on casing while WOC. Nitrogen Injection Foamed cementing done without using (foamed cement) automated, process controlled injection —4 equipment. Foamer and Nitrogen For foamed cement, foamer and/or at Proper Ratio nitrogen ratios not within ± 5 % of —4 design. Section Total —41 0 0 0 • 1 ] ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 93 Mechanical Barrier Considerations Applicability and Risk Use of subsurface mechanical barriers 5 has been properly evaluated. Type of Barrier Appropriate barrier for well design and 35 conditions is utilized. Section Total 40 0 0 0 Mechanical Barrier Problems (Penalty Points) Set in Appropriate Packer is not set in an appropriate _5 Location location. Cementing Program Cement slurry properties and placement Designed to methods are not designed to Accommodate accommodate operational —5 Operation considerations for use of mechanical barriers. Successful No positive indication of tool operation _5 Indicator(s) and setting. Section Total —15 0 0 0 Post Primary Cementing Job Parameters Annular MonitoringAnnulus is monitored and kept full 4 during WOC. WOC Before Nippling WOC before nippling down BOP stack 20 Down until criteria are met. Pressure Test Casing Casing is pressure -tested when cement 4 plugs are landed. Annular Top Out Performed based on requirements and 4 Procedure conditions. Cement returns are observed or Cement Top calculated and measured top of high 4 performance cement is above flow zone. Section Total 36 0 0 0 WORKSHEET Total 275 0 0 0 • Bibliography [1] Gai, H., Walz, G., Nakamura, D. and Burnham, M., "The Resurgence of ECP's at Pruhdoe Bay/North Slope," paper SPE 35592 presented at SPE Western Regional Meeting in Anchorage, Alaska, 22-24 May, 1996. [2] Suman Jr, G. O., and Wood, E., "Predicting Seal Effectiveness of Cement -inflated Packers," World Oil, May 1995. [3] Bannerman, M., Calvert, D.G., Griffin, T., Levine, J., McCarroll, J., Postler, D., Radford, A., and Sweatman, R., "New API Practices for Isolating Potential Flow Zones During Drilling and Cementing Operations," paper SPE 97168 presented at the 2005 ATCE in Dallas, Texas, 9-12 October. 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[37] "Energy Loss Database," an August 2004 publication by Willis Limited, a Lloyd's Broker. See Ref. [38] Willis website link to download. [38] http://www.willis.com/documents/publications/industries/energy/2155—energy%20—loss—database.pdf. [39] "Worldwide Cementing Practices," First Edition, API book publication, January 1991. [40] Rederon, C., Brisac, J., Tartera, M., Repal, S.N. and Labbe, C., "Drilling and Production Problems in Hassi- Messaoud Field," paper SPE 149 presented at the 1961 Fall Meeting of the Society of Petroleum Engineers of AIME, 8 — 11 October, Dallas, Texas. [41] Morgan, D.R., "Field Measurement of Strain and Temperature While Running and Cementing Casing," paper SPE 19552 presented at the 1989 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8 — 11 October. 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[45] Bearden, W.G., and Lane, R.D., "You Can Engineer Cementing Operations to Eliminate Wasteful WOC Time," The Oil and Gas Journal, July 3, 1961. [46] Mueller, D.T., "Redefining the static gel strength requirements for cements employed in SWF mitigation," paper OTC 14282 presented at the 2002 Offshore Technology Conference, Houston, Texas, May 6 — 9. [47] http://www.mms.gov/glossary/index.htm. [48] http://www.osha.gov/SLTC/etools/oilandgas/glossary_of__terms/glossary_o_terms—a.html [49] http://www.spwla.org/, see "Library & Info" at bottom of webpage. [50] http://www.oilandgasuk.co.uk/glossary.cfm. [51] hftp://www.spe.org/glossary/wiki/doku.php �J ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 97 • • 0 • • • E'/7%iiJ�,�� AMERICAN PETROLEUM INSTITUTE 1220 L Street, NW Washington, DC 20005-4070 USA 202-682-8000 Additional copies are available online at www.api.org/pubs Phone Orders: 1-800-854-7179 (Toll -free in the U.S. and Canada) 303-397-7956 (Local and International) Fax Orders: 303-397-2740 Information about API publications, programs and services is available on the web at www.api.org. Product No. G66201 • • L
