CO2 geologic-sequestration (GS) via injection wells into suitable subsurface strata is a safe, cost-effective way to mitigate climate change. However, using well cements to zonally isolate CO2 for up to 1,000 years, as required for permanent reservoir storage, may be challenging. Some researchers claim that cement fails when exposed to CO2, leading to potential leakage to the atmosphere or into underground structures that may contain drinking water. Other investigators show cement samples from 30 to 50 year-old wells that have maintained sealing integrity and prevented CO2 leakage, even though some degree of carbonation was found. This paper presents likely reasons for this disparity between research lab test results and actual well performance data, along with best practices to provide efficient cement-based zonal isolation of CO2 storage zones. Also discussed are recent laboratory results from testing cement samples surrounded by formation material treated at two different downhole conditions. In one case, the cement specimens were treated with a 40% humid CO2 at 140°F and 2,000 psi whereas in the second case they were treated with saturated CO2 in water at 200°F and 2,000 psi for various time intervals. Results show that samples of carefully designed cement systems had a mild carbonation without any sign of loss of mechanical or sealing integrity which could lead to zonal isolation failure. A newly-applied laboratory testing method used for decades for other purposes is proposed to determine CO2 sealing performance by cement in a relatively short time period compared to previous methods. In summary, this paper discusses a comprehensive approach that may be taken to help ensure long-term, effective CO2 zonal isolation in new wells, in existing wells (via remedial solutions), and in wells to be plugged and abandoned. Introduction The oil and gas industry has 45 years of safe and effective experience in injecting CO2 for enhanced oil recovery (EOR). That history starts with field tests such as a 1964 (Holm) trial at the Mead Strawn field. In that trial, a "large slug" of CO2 increased oil production from the field as much as 82% compared to the best results achieved in the water flood. Prior to this, conceptual work included the first patent for CO2 EOR technology in 1952 (Whorton). Large scale CO2 EOR projects began in 1972 (Langston) with the SACROC (Scurry Area Canyon Reef Operators Committee) Unit of the Kelly-Snyder Field in West Texas. The SACROC CO2 EOR project is still active today. It is joined by a growing number of commercial projects, including 105 in the USA, seven in Canada, and 12 in other countries (EOR Survey). The overall process technology, operational experience, and regulatory procedures developed for CO2 EOR are field-proven with a great record of successful applications. This outstanding record includes thousands of new wells, previously-drilled wells, and well abandonments that, with a few exceptions, have all used Portland-based cement for CO2 zonal isolation. The exceptions (non-Portland cements for CO2 zones) are an estimated 0.15 % of the total (16,348) of all CO2 EOR wells (EOR Survey). In the United States alone, the EOR Survey reported operations in 15,373 CO2 injection and production wells, more than 3,500 miles of high-pressure interstate CO2 pipelines, and countless miles of flowlines to each well. Current USA production is about 245,000 barrels of oil per day from CO2 EOR projects. Several years ago the IPCC defined the CO2 EOR process as subsurface CO2 storage (also called CO2 geologic-sequestration). In this CCS (carbon capture and storage) process permanent CO2 storage results from CO2 displacing hydrocarbons from reservoir pore spaces and subsequently being trapped or geologically sequestered within the reservoir's porosity. Kinder Morgan recently estimated that 655 million tons of CO2 have been injected, produced, and recycled back into the reservoir in EOR projects over the past 37 years. This average of 17.7 million tons per year is equivalent to the total emissions of approximately four coal-fired, electric power plants of 500 MW capacity each.

Summary Lost circulation has been one of the major challenges that cause much nonproductive rig time each year. With recent advances, curing lost circulation has migrated from "plugging a hole" to "borehole strengthening" that involves more rock mechanics and engineering. These advances have improved the industry's understanding of mechanisms that can eventually be translated into better solutions and higher success rates. This paper provides a review of the current status of the approaches and a further understanding on some controversial points. There are two general approaches to lost circulation solutions: proactive and corrective, based on whether lost circulation has occurred or not at the time of the application. This paper provides a review of both approaches and discusses the pros and cons related to different methods—from an understanding of rock mechanics and operational challenges. Introduction Lost circulation (LC) is defined as the loss of whole mud (e.g., solids and liquids) into the formation (Messenger 1981). There are two distinguishable categories of losses derived from its leakoff flowpath: Natural and Artificial. Natural lost circulation occurs when drilling operations penetrate formations with large pores, vugs, leaky faults, natural fractures, etc. Artificial lost circulation occurs when pressure exerted at the wellbore exceeds the maximum the wellbore can contain. In this case, hydraulic fractures are generally created. During the last century, lost circulation presented great challenges to the petroleum industry, causing significant expenditure of cash and time in fighting the problem. Trouble costs have continued into this century for mud losses, wasted rig time, and ineffective remediation materials and techniques. In worst cases, these losses can also include costs for lost holes, sidetracks, bypassed reserves, abandoned wells, relief wells, and lost petroleum reserves. The risk of drilling wells in areas known to contain these problematic formations is a key factor in decisions to approve or cancel exploration and development projects. Background literature (Messenger 1981) on the subject describes many methods and materials used to remedy lost circulation. Many of these methods worked in some wells but not in others. Trial and error applications almost always resulted in a costly learning curve. A field practices study (API 1991) of cementing wells, published by the American Petroleum Institute (API) in 1991, compiled drilling and production surveys and trade journal data for 339 fields worldwide between 1980 and 1989. The number of fields in each area is presented for general information and may not represent all wells or fields in that specific area. The North American fields include fields in Canada, Mexico, and the USA. Listed among the many types of data sourced in this study is LC information in relevant fields. This LC data was analyzed for this paper to obtain the LC event frequencies of occurrence presented in Table 1. The LC data analysis indicates that up to 45% of all wells in the 339 fields require intermediate casing or drilling liner strings to isolate LC zones and prevent LC while drilling deeper to total depth (TD). Even after using these extra pipe strings, LC events still occurred in 18 to 26% of all the hole sections drilled in relevant fields. Some fields had higher occurrences of LC events ranging from 40 to 80% of wells. In recent years, these percentages likely increased as the number of shallow, easy-to-find reservoirs steadily declined and industry operators intensified their search for deeper reservoirs and drilled through depleted or partially depleted formations. Conventional lost-circulation materials (LCM), including pills, squeezes, pretreatments, and drilling procedures 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. To address these issues, new LC solutions and concepts, such as borehole strengthening or wellbore pressure containment (WPC), evolved (Alberty and Mclean 2004; Aziz et al. 1994; Fuh et al. 1992). The mechanisms behind various means proposed and used to enhance WPC are still debated and are not fully understood. Proposed mechanisms include sealing incipient fractures at the wellbore wall; propping open multiple short fractures at the wellbore wall, thus increasing compressive stresses around the wellbore; and sealing fractures with various materials using a hesitation-squeeze technique. Based on the ongoing debate of these emerging new technologies for controlling lost circulation, this paper intends to provide a comprehensive review and analysis for a better understanding of both proactive and corrective borehole strengthening technologies.

This paper provides substantial and compelling evidence from API (American Petroleum Institute) CCS (Carbon Capture & Storage) Work Group and other studies of CO2 EOR (enhanced oil recovery) and CCS projects showing that CO2 capture, transport, and (GS) geologic-sequestration can be a safe and effective method to reduce GHG (greenhouse gas) emissions and mitigate climate change. The paper summarizes how the oil and gas (O&G) industry has achieved great success in engineering the process to capture, transport, and inject CO2 in EOR projects. This success is seen in over 37 years of safe and environmentally friendly large-scale operations, lessons learned, technical advancements, and millions of tons of CO2 injected. Third party investigations to evaluate this successful record are discussed, including some completed ones that have published statements validating the O&G industry's success. Now that CCS is being widely considered and a few countries have begun to implement commercial-scale CCS projects, technology transfer efforts such as this paper are needed to share the experience of the oil and gas industry and the major contribution it can make as part of the solution for climate change. Introduction Historical Overview. Since the first patent for CO2 EOR was granted in 1952 (Whorton), the O&G industry has spent many tens of billions of dollars developing and implementing CO2 EOR technologies, asset development, and operational experience. As new sources of CO2 have become available, field testing and demonstration or pilot project activities have been conducted. These development and improvement efforts have been continuous since the first project in 1964. The first large-scale, commercial CO2 EOR project began operations in 1972 at the SACROC field in West Texas, which continues in operation today. Many more have started since then and by 2008 had reached a total of 112 projects, as reported in the EOR Survey by the Oil and Gas Journal (O&GJ, 2008). Since 1952, numerous patents, best practices, equipment, and products have been developed for CO2 EOR well construction and injection/production operations. Innovative, cost-effective materials, equipment, and methods continue to be developed and implemented such as the recent introduction of real-time, smart-well operations at SACROC. Much of this knowledge has been documented in hundreds of technical papers and several books that have been published on the subject including many applicable API standards and specifications. CO2 EOR Technology for CCS Deployment. Underground geological storage of CO2 is a promising technology for reducing greenhouse gas (GHG) emissions because much of the technology developed by the oil and gas industry associated with natural gas processing and CO2 EOR can support the sound implementation of CCS and huge storage capacity exists in deep saline formations, depleted oil and gas reservoirs, and unmineable coal seams. According to a major report by the Intergovernmental Panel on Climate Change (IPCC, 2005), as much as 55 percent of a worldwide GHG mitigation effort thru 2100 could be achieved through carbon capture and storage. The IPCC also expresses confidence that CO2 can be stored safely over very long periods of time and cites several studies as evidence that the potential for leakage decreases the longer the CO2 is underground.

The challenges facing offshore CO2 enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects are presented in this paper along with potential solutions based on the oil and gas (O&G) industry's CO2 EOR and CCS experience and technology as applied in a few offshore locations. Prospects for future offshore projects are also discussed based on the O&G industry's experience, technology, and best practices. These achievements are the result of a safe and successful 58-year history of well construction and operations in land-based, commercial CO2 EOR projects. Achieving CCS by injecting CO2 into saline formations or for EOR in mature oil reservoirs is a safe and effective method to reduce GHG (greenhouse gas) emissions. The IPCC has defined enhanced oil and gas recovery via CO2 injection as a recognized form of CCS. Using existing industry experience and technology developed over the past 58 years, CO2 injection into oil reservoirs for EOR has been safely and effectively applied in 18,077 active wells worldwide (17,112 in USA) according to the latest EOR survey (O&GJ, 2010). Production from natural gas reservoirs has also benefitted from CO2 injection in enhanced gas recovery (EGR) applications. Key results are summarized and major conclusions presented from studies by the American Petroleum Institute; Advanced Resources International; European Commission, DG-Joint Research Centre, Institute for Energy; Kinder Morgan; Norwegian Petroleum Directorate; Bellona Foundation; Norwegian University of Science and Technology; SINTEF Petroleum Research; and others. Conclusions from these studies point to the substantial value of current industry experience as a sound basis for offshore CCS applications. Offshore CCS/EOR may be more viable than onshore options for areas with high population densities, where offshore reservoirs are within reasonable distances from land, or where there are existing offshore O&G facilities and wells. The technical knowledge base of the petroleum industry can be leveraged for the development of CCS with a strong understanding of the pros and cons of offshore projects, operating experience with safe and economic CO2 capture, transportation, injection, and understanding of subsurface formations for future CO2 EOR/CCS applications. Introduction Oil and Gas Industry Experience The first patent for CO2 EOR was granted in 1952 (Whorton). The Texas Railroad Commission (TRRC report) proposed CCS rule states that " the first three projects (immiscible) were in Osage County, Oklahoma from 1958 to 1962.?? Another early CO2 EOR project was in Jones County, near Abilene, Texas in the Mead Strawn field in 1964 (Holm). The first large-scale, commercial CO2 EOR project (Langston) began operations in 1972 at the SACROC field in West Texas, which continues in operation today. Many more CO2 " flood?? EOR projects have started since then. By 2010, CO2 EOR projects had reached a global total of 127 (112 in USA) with 12 more planned for the USA, as reported in the EOR survey by the Oil and Gas Journal (O&GJ, 2010). Rising oil prices, low cost sources of high purity CO2, and access to miscible fields with large amounts of unrecovered oil have supported growth in CO2 based EOR in the U.S., which now accounts for 272 mbd (O&GJ, 2010) or over 8% of total Lower 48 crude production of 3.22 mmbd in the 2nd quarter 2010, as reported by the U.S. Energy Information Administration.

Insufficient borehole pressure integrity (BHPI) is a significant drilling challenge in deep, high-temperature, high-pressure (HTHP) wells in south Texas, as it is in many wells. Shales and/or sands weakened by depletion, leaking faults, or unfavorable rock properties result in lost returns when mud weights are close to pore pressures. In one field, short (~50 ft) transitions from normal (11 lb/gal) to overpressured (17.5 to 18.0 lb/gal) Frio formations compound the severity of this challenge. Setting casing to isolate normal-pressure from high-pressure zones can be problematic if faults exist at the casing shoe and/or the cement job does not provide a good hydraulic seal. In one case, the intermediate casing shoe failed to test, and conventional cement squeezes were unable to correct the problem. In the productive portion of the well, preventing skin and or formation damage in an interval that had a wide range of pore pressures (8.5 to 17.8 lbm/gal), was a major concern with any treatment option to increase borehole integrity. This paper describes successful applications of new BHPI treatment materials and methods for increasing borehole integrity. BHPI treatments have allowed higher drilling and cementing circulation rates. This has helped optimize drilling performance and improve well conditions during cementing operations, which has resulted in improved primary cementing success. It has been suggested that skin damage in the zones of interest can be minimized since BHPI treatments can be designed and targeted to only enter areas with low BHPI. In one case, a BHPI treatment entered a low-pressure productive interval, which, after a planned stimulation program, did not seem to affect production performance. In another case, after BHPI treatments helped increase wellbore integrity, the productive interval in one well was successfully cemented without requiring a drilling liner, which would have limited completion flexibility. A theoretical rock mechanics model is discussed to help explain how the new BHPI treatments can rapidly and substantially increases the pressure integrity of holes located across both sand and shale formations. Minor BHPI filtrate invasions during tests in high- and low-permeability sandstone cores should explain why the new BHPI system also limits formation damage. Introduction Many types of formations can have poor BHPI integrity immediately below the casing shoe and deeper in the hole to the next casing-seat depth. This lack of pressure sealing, structural integrity to contain planned bore-hole pressures may be the result of natural in-situ stresses that cause weak BHPI points or defects in rock such as natural fractures and leaking faults. Drilling induced stresses that create new fractures or open sealed faults make up the balance of causes for low BHPI along with a significant number of chemically sensitive formations that weaken upon exposure to drilling fluids. Equivalent-circulating-pressure (ECD) and swab/surge pressures during drilling, tripping drill pipe, running casing, and cementing may exceed these low BHPI values. In the drilling cases, problematic conditions can occur, such as severe lost circulation, inadequate hole cleaning, lowered fluid column pressures, and subsequent formation fluid influx. During drilling, problematic conditions can occur, such as severe lost circulation, inadequate hole cleaning, lowered fluid-column pressures, and subsequent formation fluid influx. Exceeding BHPI values during primary cementing can jeopardize zonal isolation and casing support. These incidents often increase well development costs by forcing operators to set casing early, run a drilling liner, use a contingency casing string, and perform remedial cementing. In some wells with known low BHPI conditions, such as deepwater and HTHP wells, budgets must account for additional pipe strings necessary for drilling and completing the well. In addition, a significant number of well control problems occur from lack of BHPI.

fax 01-972-952-9435.References at the end of the paper. AbstractDrilling and cementing operations in certain subsalt wells in the Gulf of Mexico (GOM) and other areas have long challenged operators and contractors. These wells have thick, deep salt formations with shear zones just above and below the salt, resulting in high unexpected costs during drilling. Such formations are often referred to as rubblized or disturbed shale zones. One theory proposes that, during geologic periods, the movement of adjacent salt formations induces shearing stresses that cause deformation, brittle failure, and fracturing in the surrounding shales. Costly drilling problems in these zones are primarily caused by the narrow margins between pore and fracture pressures that result in severe lost circulation, hole instability, and high-pressure kicks. Some of these wells also exhibit uncontrolled gas flows and underground water flows. Many GOM deepwater blocks and shelf blocks have massive salt structures and potential hydrocarbon reservoirs, but the trouble costs and difficulties associated with drilling these wells have forced operators to plug and abandon some wells and completely avoid others.Conventional lost-circulation and hole-stabilization treatments have been minimally successful in many subsalt wells. However, new wellbore-stabilization and cementing programs designed for subsalt wells can help ensure well control and integrity during drilling and production operations. This paper provides information for helping to improve subsalt drilling operations and lower well-construction costs. In addition, the failures and successes of lost-circulation treatments performed during drilling operations in shear and salt zones will be explained. Primary cementing operations that help provide cost-effective zonal isolation and well integrity in these zones are presented, as well as best practices and proposals for cementslurry design and mud displacement. Laboratory studies and cost comparisons that help justify replacing traditional materials and procedures with these cementing programs are also presented.

fax 01-972-952-9435.References at the end of the paper. AbstractDrilling and cementing operations in certain subsalt wells in the Gulf of Mexico (GOM) and other areas have long challenged operators and contractors. These wells have thick, deep salt formations with shear zones just above and below the salt, resulting in high unexpected costs during drilling. Such formations are often referred to as rubblized or disturbed shale zones. One theory proposes that, during geologic periods, the movement of adjacent salt formations induces shearing stresses that cause deformation, brittle failure, and fracturing in the surrounding shales. Costly drilling problems in these zones are primarily caused by the narrow margins between pore and fracture pressures that result in severe lost circulation, hole instability, and high-pressure kicks. Some of these wells also exhibit uncontrolled gas flows and underground water flows. Many GOM deepwater blocks and shelf blocks have massive salt structures and potential hydrocarbon reservoirs, but the trouble costs and difficulties associated with drilling these wells have forced operators to plug and abandon some wells and completely avoid others.Conventional lost-circulation and hole-stabilization treatments have been minimally successful in many subsalt wells. However, new wellbore-stabilization and cementing programs designed for subsalt wells can help ensure well control and integrity during drilling and production operations. This paper provides information for helping to improve subsalt drilling operations and lower well-construction costs. In addition, the failures and successes of lost-circulation treatments performed during drilling operations in shear and salt zones will be explained. Primary cementing operations that help provide cost-effective zonal isolation and well integrity in these zones are presented, as well as best practices and proposals for cementslurry design and mud displacement. Laboratory studies and cost comparisons that help justify replacing traditional materials and procedures with these cementing programs are also presented.

why the treatment system minimizes or prevents skin damage. Skin damage in the zones of interest may be prevented or minimized by BHPI treatments that only enter leaking fractures or faults.Further development and deployment of BHPI treatment technology promises a step-change in industry practice to optimize well plans with lower cost programs for drilling fluids, casing design, cementing, and completion equipment. Optimized well designs should reduce both drilling days and flat time by allowing operators to drill smaller-diameter holes while using fewer casing strings to achieve the same production-string dimensions. AbstractInsufficient borehole pressure integrity (BHPI) is a major drilling challenge in deep, high-temperature, high-pressure (HTHP) wells in California and other areas. Shale and sandstone formations with low BHPI may be weakened by leaking faults/ fractures or poor rock properties, causing lost returns with mud weights close to pore pressures. Drilling through depleted or low pore pressure formations with some probability of drilling into higher pressured zones in the same hole section compounds the severity of this challenge in the Temblor formation in Kern County, California. This challenge was solved by an innovative treatment applied in the Berkley East Lost Hills No. 1 well. Compared to conventional methods, it increased leakoff test (LOT) and formation-integrity test (FIT) pressures to incremental values higher than those typically seen in the industry. Increasing BHPI allowed an additional 960 ft to be drilled before a 7-in. liner was set, and the well was drilled to 19,724 ft. This depth met the objective of the well (to obtain full penetration through the objective sands) and allowed the subsequent discovery of a pay zone. If the new treatment to increase the LOT had not been used, the 7-in. liner would have been set early, and it is unlikely that the discovery zone would have been penetrated.Preventing skin and formation damage in potential zones of interest while treating weak points was another major concern heightened by a wide range of pore pressures. This paper discusses a theoretical mechanism to help explain how the treatment rapidly and substantially increases pressure integrity across both sand and shale formations. Minor penetrations in high-and low-permeability sandstone-core tests help explain fax 01-972-952-9435.References at the end of the paper.