Maintaining healthy well integrity in heavy-oil thermal wells is a challenge. Steam causes significant variation in temperature along the wellbore resulting in excessively high stresses that can result in parted casing or even a complete casing failure. Determining casing break/failure condition is an important part of managing thermal well integrity. Identifying potential risks based on findings from electromagnetic (EM) casing inspection logs is essential to plan mitigation actions. EM casing inspection logs can also be run prior to putting wells on steam injection to establish a baseline and regularly evaluate well integrity via a time-lapse methodology. In this paper, we have outlined the successful application of Pulsed Eddy Current (PEC) Electromagnetic casing inspection technology in thermal well integrity. One of the major benefits of PEC casing inspection technology is a reliable method to locate casing breaks. It provides casing inspection without retrieving tubing (first pipe) that saves time and costly workover. This paper briefly explains the PEC technology, how it has been deployed, and the methodology developed to quickly and clearly identify casing breaks because one of the evaluation challenges is that the typical thermal casing break occurs in the vicinity of the casing collar. We have demonstrated in the paper validation of the PEC technology for detecting casing breaks. It includes downhole comparison with a traditional multi-finger caliper log after the tubing is pulled. The paper includes some case study examples of how PEC has been used to successfully identify casing breaks and conclude with a summary collected over five years of PEC application with a 100% success rate in more than 200 Canadian heavy oil wells.

In heavy oil thermal wells, wellhead flanges are typically welded to casing pup-joints, with butt welding on the inner wall, and fillet welding on the outer wall. For the field operation, it was found that after 40 days of steam injection, approximate 50% of the wellhead production casing pup-joints exhibitedleakage, with longitudinal crack in casing joints. Fracture of the wellhead flange and the casing led to leakage of significant amount of toxic and harmful hydrogen sulfide which was not part of the l formation fluid. Ultrasonic flaw detection was performed on the failed casing joints. Andfound initiation of longitudinal cracks in the butt and fillet welds. Further tests were performed to obtain chemical composition, mechanical properties, charpy impact energy, and hardness values for the casing, flanges, and welds. The analysis showed poor weldability for the casing and flange materials, with weldability carbon equivalent greater than the critical value (≥0.6%). Microcracks were presented in the welds. Metallographic structure, material composition nearorigins of the cracks and crack propagation zone, and the welds were examined..Micro cracks along the wall thickness in fusion line and casing heat-affected zone were found. Note that the materialin the casingmiddlewallis tempered sorbite, with the nearby external surface of the weldmetallographic structureismartensite of phase transition. The weld and heat-affected zone had obvious phase transitions of IAF+B+F+P. Blind-hole method was used to quantifyhoop and axial stresses in the casing inner wall and the external fillet welds. It was found that location of the maximum hoop tensile stress coincided with the maximum tensile principal stress. With the maximum tensile residual stress 389MPa at 4 mm from the weld-fusion line in the casing external wall, and with the shielded metal arc welding heat-affected-zone width of 6-8.5 mm, the tensile residual stress in the heat-affected zone was 2.2 times higher than the residual stress in the casing body. The weld material at the maximum tensile residual stress location was tested for SSCC. Stress corrosion was observed for all threes specimens at ambient temperature within 12 hours. Using SEM method, the failure and SSCC analyses showed that the fracture morphology was flat and integunularfracture, and surface was covered with agglomerate corrosion products. Sulfur element was analyzed by means of EDS. It was found that the mass percent of S element in fracture secondary cracks coincided with the measured value of the SSCC fracture test. Therefore, it was concluded that the casing pup-joint longitudinal cracking was SSCC.related. Note that the polysulfone-drilling mud pyrolysis produces hydrogen sulfide was above 150 ° C at which H2S may be produced by the drilling mud. During stages with no steam injectat ambient temperature environment, using high grade SSCC non-resisitant thermal recovery well casing, as well as welding causedhigh residual stress, and high hardness martensite, were the main reasons for the longitudinal cracking in the casing. Therefore, it is recommended that the polysulfone-drilling mudshould not be used in drilling for thermal recovery wells. The use of welded connections should also be avoided or the undesired effects should be mitigated.

Depletion of conventional hydrocarbons reservoirs have led oil and gas operators to extend the boundaries and pursue production from reservoirs with high viscosity hydrocarbons that in the past were impossible to be produced and allow the hydrocarbons in place to flow to the surface with conventional production methods. With the introduction of enhance oil recovery techniques (EOR) operators has been able to economically produce from these reservoirs. The steam flood is an EOR technique that allows heavy oil hydrocarbons to be produced and increase the recovery of original oil in place (OOIP). This technique requires high temperature steam to be injected into the reservoir in order to allow hydrocarbons production, introducing challenges in order to maintain well integrity and long term life of the well. Suitable surface facilities, equipment and materials that withstand these challenging conditions are required in order to guarantee the success of the project. In a heavy oil shallow reservoir in Bahrain, a steam flood pilot project has been executed, injecting steam up to 650ºF into the injectors wells in order to enhance the hydrocarbons production in the adjacent production wells. Conventional cement systems will fail when exposed to the given conditions as the mechanical properties of such cements are not sufficient to withstand the stresses created in this extreme temperature environment. This will consequently threaten the well integrity and success of the project. In order to provide a reliable and durable zonal isolation, an engineered cement system has been introduced. This cement system possesses sufficient flexibility (low Young's modulus), and a high coefficient of thermal expansion to withstand the metal casing expansion during the heating step of the process, without failure. This cement system exhibits stable mechanical properties for a long duration during the whole process of the heavy oil production and can be mixed and pumped with conventional cementing equipment. It is placed at low (110-140°F) temperature, acquires sufficient compressive and tensile strength to withstand the heating cycles. Over 50 wells have been cemented using this technology in Bahrain. Cement bond longs and temperature logs demonstrate well integrity has been achieved, allowing the steam to be injected into the target reservoir. Furthermore, no issues have been seen related to steam break through to surface. The project has been implemented for over 4 years with no sign of wellbore integrity failure. This study covers several aspects of the design, execution and evaluation of the cement system.

Thermal well service conditions have presented a significant challenge to the sealability of casing connections. Over the years, industry has established various standards, protocols and guidelines for assessing the sealability performance of casing connections to be used in thermal well applications. The use of Finite Element Analysis (FEA) has been increasingly incorporated into the connection performance evaluation process. FEA evaluation requires the use of an appropriate criterion that relates the connection seepage rates to the applied internal pressure differential, contact stress profile on the radial seal surface, surface roughness, thread compounds and various other factors such as environmental impacts. This paper presents experimental work that has been undertaken to investigate the metal-to-metal seal behavior in premium casing connections. The physical tests simulated a series of metal-to-metal seals under various levels of gas pressure and seal contact stress. The impacts of seal length, tubular diameter, surface roughness, thread compound and corrosive medium were investigated. The experimental results were used to validate the sealability criterion which is proposed for use in evaluating thermal well casing connections.

The severe loading conditions experienced by the casing strings in thermal wells used in Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) operations pose a significant challenge in terms of the casing connection sealability performance and integrity. The industry has recently developed standards and protocols for assessing and qualifying connection sealing performance for such applications. The comprehensive programs include both Finite Element Analysis (FEA) evaluations and a series of full-scale physical tests. The FEA evaluations are required to determine the worst-case connection design scenarios, in terms of geometry, material properties and make-up torque, for fabrication of the specimens to be assessed in the physical tests. The scope of the FEA work includes analyzing the connection sealability performance under selected load cases representative of the intended field service conditions. A suitable minimum sealability criterion is required to assess the adequacy of the predicted connection sealing performance for the specific application. This paper presents the results from an experimental metal-to-metal seal investigation and describes their use to establish a simplified sealability criterion for premium casing connections. The leakage response of several different seal samples was determined as a function of contact stress level for differential gas pressures of 3.3, 7.4, 12.1 and 16.5 MPa, corresponding to Application Severity Levels (ASL) of 240, 290, 325 and 350 per ISO/PAS 12835. The test results were used to characterize the relationship that existed between the leakage rates recorded in the tests and the selected control variables: differential pressure; seal length; tubular size; and seal contact stress level. The paper also demonstrates the use of the proposed sealability evaluation criterion in conjunction with the FEA results established for a 244.5 mm, 59.5 kg/m L80 premium connection subjected to thermal cycle loading.

This paper focuses on the strain based design and field application of thermal well casing for cyclic steam stimulation process. The heavy oil is a main field of China petroleum industry, where the cyclic steam stimulation process has been widely used and playing the dominating role in production. Generally the casing damage rate is 15-30% under this process, which has resulted in a large economic cost. The high damage rate is mainly caused by the current strength design method, where both the room and elevated yield strength were considered not beyond anticipated field thermal stress. In fact the casing material will serve in cyclic thermal elastic-plastic deformation state and the single yield strength is not sufficient for long term thermal stimulation process. This paper presented a new strain based design method for thermal casing string. New material parameters were proposed to build the safety evaluation principle throughout the service life. For thermal casing the material plasticly deforming limit, called as allowable strain, is determined by the homogeneous deforming capacity. For design strain, the material creep rate equation is introduced to evaluate the accumulative elevated strain in long term service together with initial install strain, thermal strain and soil strain. When the design strain is not more than the allowable strain the casing material will safely serve throughout the whole life. In addition the strain fatigue limit is measured to evaluate the material safety for thermal cycle life. According to the factual field engineering environment the gas tight thread joint was adopted to prevent steam leak which otherwise will cause a large transversal stress between different formations and result in slip deformation of casing string. Before the engineering operation the full scale test procedure was proposed and finished to evaluate the string integrity in multiple thermal cycles. From 2011, this method was used in Xinjiang oil field for eight wells for more than 14 steam cycles and all the experiment wells served well without any damage. Several wells were cyclic measured through multi arms inspector and the data showed that all the casing deformation located in controlled scope except that only one has obvious deformation because poorer cementing quality. The field practice has showed that the new method has better fitness for thermal wells.

Cement plays a vital role in maintaining the long term integrity of oil and gas wells by forming a robust and impermeable barrier and ensuring zonal isolation by restricting the flow of fluids between different geological zones. In-situ thermal stimulation methods such as SAGD place the casing cement under extreme stresses due to the rapid temperature increases that occur during initial steam stimulation. The prevailing mentality in the industry for many years was that compressive strength alone was a satisfactory predicator of a cement's ability to withstand downhole stresses. However, the stresses induced in a SAGD well are often not compressive, but rather radial in nature due to the large thermal expansion of the casing during heat up, making tensile failure of the cement more prevalent. This problem is compounded by the fact that the tensile strength of conventional oil well cements is typically only 8 – 12% of the maximum compressive strength. To best mitigate the risk of cement failure, cement with a higher tensile strength is a better choice. In this paper a new fiber based tensile strength-enhancing cement additive for thermal oil well applications, such as those used in SAGD, is described. At an optimized loading of 0.5% by weight of blend (BWOB) the fibers gave a 20% improvement in tensile strength under mild temperatures (25–50 °C) and over 35% improvement in tensile strength at 250 °C. This significant enhancement in tensile strength occurs without significant detrimental effects on other mechanical or slurry properties. The stability of the additive is demonstrated by a full mechanical property evaluation (tensile strength, compressive strength, Young's modulus) after long-term high temperature exposure (one month at 250 °C). Extensive field testing with fiber-containing blends demonstrated that the fibers could be readily dry bulk blended on a multi-tonne scale, and successfully pumped with existing conventional dustless mixing systems. The significant enhancement in tensile strength, without sacrificing any other performance parameters, is expected to substantially improve well integrity in the demanding environments encountered in SAGD.

A “Silver Bullet” is defined as a solution that relies on using one portion of a number of complex processes to quickly and easily achieve a desired result. In the case of Steam Assisted Gravity Drainage (SAGD) casing cementing, the objective is to achieve complete annular zonal isolation from the intermediate casing shoe to surface. Cement is often cited as providing a “Silver Bullet” solution for a number of well construction deficiencies. An integrated design approach is a philosophy that incorporates critical design criteria, operational best practices and fit for purpose equipment to achieve a desired result. An integrated design approach is only effective if full participation occurs from both the operator and service providers. Design and operations personnel should be fully utilized in this philosophy. This approach has been employed with respect to the well construction and casing cementing operations at Foster Creek/Christina Lake (FCCL) SAGD projects. The operator and cementing service provider employed an integrated design approach to SAGD cementing operations and the results are presented in this paper. SAGD wells present sub-surface well construction engineers with a difficult environment in which to achieve a competent annular seal when cementing intermediate casing strings. SAGD well designs typically consist of large diameter drill holes and casing, set horizontally at relatively shallow true vertical depths (TVDs), through formations of variable competency. SAGD production operations then, via steam injection, subject the wells to extreme temperature cycles up to 275°C. These operating environments require design consideration of all aspects of the drilling and casing cementing operations to achieve and maintain annular isolation. Relying on one piece of a puzzle to make up for a number of missing parts rarely provides a consistent, reliable outcome. An integrated design approach that leverages all the various aspects of wellbore construction is essential to achieving high quality well performance throughout the life of project. Drilling a hole with a uniform diameter (minimizing washouts) and trajectory, drilling fluid conditioning and solids removal, coupled with proper casing centralization and movement during cementing operations is essential to ensure an adequate cement sheath is obtained around casing. Flushes and spacers are utilized in cementing operations to seal off porous formations, reduce cement fallback and provide a reactive film on the borehole and casing to improve the quality of the cement bond. The placement of cementing fluids into wells at higher annular velocities has a 30+ year history in Western Canada of improving drilling fluid/solids removal from casing annuli and enhancing cement to formation/pipe bond, reducing well problems associated with incomplete zonal isolation and casing support. A recent introduction into SAGD cementing operations of a formulated spacer fluid and “fit for purpose“ mixing and pumping equipment has resulted in quantifiable improvements in intermediate casing bond quality. A cementing system has been designed to provide these results, while reducing the required location personnel and equipment footprint. The background, case history and the definitive bond log comparison will be presented to illustrate these improvements.

Cement is critical to well integrity. It provides hydraulic isolation, preventing fluid flow between producing zones, ground water aquifers, and the surface. In steam stimulated wells, such as for Steam Assisted Gravity Drainage (SAGD) or Cyclic Steam Stimulation (CSS), the heat-up period places severe mechanical loading on the cement sheath. Heat is transferred from high temperature steam, through completion strings and annular fluids, to the casing, cement and formation. Thermal expansion of the casing combined with axial constraint make radial expansion of the casing the most severe in the energy industry. Furthermore, with constrained expansion of the cement, the range of deformations that must be accommodated by the cement sheath while maintaining isolation is challenging. These deformations can cause shear or tensile failure of the cement and result in leakage paths through the cement ( e.g. cracks or global changes in cement permeability), or leave a micro-annulus when recovery has been completed and thermal operations halt. This paper describes the impact of key thermal and mechanical properties on the structural performance of cement blends in thermally stimulated wells. The work is based on laboratory testing of thermal cement blends and the use of Finite Element Analysis (FEA) to examine cement performance under operating conditions. The findings provide insight into important cement behaviours that impact longterm integrity of cement and highlight the significance of conducting tests under field representative conditions. Results indicate the importance of compressive strengths, flexibility, and shrinkage/expansion characteristics to ensure the cement sheath remains structurally intact during initial heat-up.

An increasing energy demand combined with the natural decline of old field discoveries has forced oil producers to develop and improve returns from existing assets. In Latin America, many major oil companies have been interested in heavy oils. Higher oil prices and improvements to technology allowing recovery factors up to 30% have made these reservoirs more attractive to operators. In Colombia, heavy oil fields are being developed in the Magdalena Medio area using steam injection as a thermal recovery method. Cyclic steam stimulation (CSS) is used and consists of three stages: injection, soaking, and production. Steam is first injected into a well for a certain amount of time to heat the oil within the surrounding reservoir to a temperature at which it flows. After sufficient steam has been injected, the steam is usually left to "soak" for a predetermined time period. Finally, oil is produced out of the same well. This process can cause high stress in the wellbore because of the high temperatures used and the cyclical nature of dramatic temperature changes. The elevated temperatures can reach up to 350°C (650°F) during thermal cycling, which, in turn, can potentially cause radial fractures or debonding of the cement, thus potentially compromising the zonal isolation. Achieving zonal isolation within these shallow vertical and horizontal wells (90° and 2, 200 ft measured depth [MD]/1, 396 ft true vertical depth [TVD]) and avoiding water communication between zones are the primary challenges encountered during these projects. This paper presents a successful methodology, lessons learned, and engineering design changes applied during the past three years to more than 200 wells in the Magdalena Medio area.

The increasing demand for energy has increased the need for production of hydrocarbon. As a result, operators have exploited more difficult reservoirs (e.g., deeper wells, remote areas, mature depleted fields, and heavy oil reservoirs). Traditional methods are not sufficient for producing heavy oil; therefore, over time, enhanced recovery methods have been researched and developed. In-situ combustion (ISC) is the oldest thermal-recovery technique. It has been used for more than nine decades for many successful projects. This method is basically the injection of an oxidizing gas (air- or oxygen-enriched air) to generate heat by burning a portion of resilient oil. Most of the oil is driven toward the producers using a combination of gasdrive, steam, and waterdrive. High temperatures and the presence of corrosive gases involved during the ISC process can present significant challenges during well isolation. Phosphate cement is a unique system capable of resisting corrosive attack, maintaining low permeability at high temperatures, and resisting the attack of carbonic acid. One of the primary challenges was developing a special phosphate cement slurry capable of setting at low temperatures to minimize the waiting on cement (WOC) as well as developing properties sufficient for resisting future stresses. A special sodium aluminate thixotropic additive was used for the first time to react chemically with the pH of this special cement system to develop a quick and high compressive strength. More than nine wells have been cemented with this system in Colombia with good results. These wells have been subjected to different stresses (production, steam injection, and ISC). This paper presents the successful application of advanced non-Portland cement slurry within the Quifa heavy oil reservoir in Colombia utilizing an ISC enhanced recovery method

A major challenge of a steamflooded field in Indonesia, one of the world's largest thermal recovery projects, is the short life of the well from the well integrity aspect. The outcome of a joint study group between the operator and the cementing service provider reveals that 77% of the injector wells drilled in a recent period of 5 years required remedial squeeze cementing operations. The operating expenditure of workover operations and the costs of the deferred production to the operator are significant; hence, a cementing solution is needed to improve the efficiency in managing the mature heavy oil reserve. The current cementing practice calls for placing the API class G cement and silica flour blended system across unconsolidated sand bodies and exposing it to large temperature changes. Results of the stress modeling predict the conventional cement system failure under the anticipated conditions of injection and workover operations. An innovative steam-resilient cement system with tailored thermal and mechanical properties up to a temperature of at least 350° C [650° F], beyond the maximum steam injection temperature of the field, is maintaining the integrity. Field trials in Indonesia confirm that this new system can be easily integrated into standard cementing operations using conventional equipment. Cement evaluation logs after cement operations prove that proper zonal isolation is achieved. All the candidate wells, first one since January 2011, are currently under the steam injection with no sign of wellbore integrity failure. This novel cement system, by keeping adequate level of flexibility and optimum thermal properties, provides a long term well integrity solution for any well exposed to similar conditions, such as in fields exposed to steam injection. Operators can rely on cement sheath integrity exposed to thermal processes to produce heavy oils.

The paper reviews two case histories about successful wellbore isolation with a suitable cementing system for a recent enhanced oil recovery / CO 2 project targeting the Thamama B formation of the Bab Far North reservoir in the UAE. The first two wells were vertical observers with zonal isolation required between the Thamama A and B. These wells were expected to exhibit a naturally corrosive environment (e.g. 56, 000 ppm of CO 2 ). To address these challenges, a fit-for-purpose cementing system, suitable for CO 2 and other corrosive fluids, was developed and successfully applied. The system was designed to isolate and protect specific Thamama zones and wellbore areas that contained gaseous or liquid corrosive CO 2 . This cement slurry was developed with a density of 16.7 ppg exhibiting expanding properties after setting to compensate potential shrinkage issues and to improve cement bond. Laboratory test results for the developed cementing system, such as compressive strength development, thickening time, expanding properties after setting, and integrity after long term exposure towards wet CO 2 , are presented and discussed. Performance requirements for cementing sytems to qualify for CO 2 tolerance are elucidated. Finally, the execution in the field and the quality of the cement job was evaluated. All of the special designs exhibited excellent bond log results. The favorable lab test results and the positive case history conclude that the developed cementing system can be a viable solution to provide long term zonal isolation in a wellbore with a corrosive environment.

Thermal well technologies, such as Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD), are widely used for the exploration of heavy oil and oilsands resources. Casing connections are one of the most critical components in thermal wells in terms of the wellbore structural and pressure integrities. High temperature operation of thermal wells inevitably imposes significant axial loads on the casing connections, and as a result, a plastic strain design concept must be used for the casing and connections. In addition, thermal well design should consider the impact of formation shear movement that may be caused by changes in the stress state in the reservoir and overburden formations during thermal operations. To meet the design challenges posed by thermal wells, premium connections are usually preferred over API connections due to generally superior structural capacity and sealability. Rigorous engineering assessments, such as full-scale physical tests and analytical evaluations are often used to assess the performance of premium connections and to identify suitable connection designs for the intended applications. These engineering assessments typically consider the in-situ load conditions specified by operators, or the load cases recommended by industry guidelines, such as the recently released Thermal Well Casing Connection Evaluation Protocol ( TWCCEP 2012 ). This paper presents approaches and considerations for using Finite Element Analysis (FEA) to conduct the analytical evaluation of casing connections for thermal wells. Such analytical evaluations serve to determine the worst-case specimen configurations (e.g. highest potential for galling or leaking) for full-scale testing programs under the load conditions specified in the Protocol, such as make-up and thermal cycles, as well as for understanding the connection performance under in-situ load cases as specified by operators, such as bending and formation shear. Analysis results provide useful insight into connection performance in terms of structural capacity, leakage resistance and galling potential. To demonstrate the use of the proposed analysis approaches and considerations, an example case with a generic premium connection geometry is analyzed and the results are presented.

Canada’s oil sands are one of the world’s largest hydrocarbon resources. The initial volume of crude bitumen in place is estimated to be approximately 260 billion cubic metres with 11 percent or 28 billion cubic metres recoverable under current economic conditions. Continually improving economics, bolstered by recent higher crude oil prices, has resulted in the International recognition of the vast potential of Canada’s oil sands. Based on publicly announced development plans through to 2015, over C$60 billion could be invested in numerous projects to develop the oil sands. Various factors have to be considered to select the proper cement for zonal isolation of thermal recovery heavy-oil wells. First the cement should be flexible enough to withstand the stresses which occur when casing expands during the heating up of the well. To reduce these stresses, the cement thermal expansion coefficient should be similar to the thermal expansion coefficient of the casing. Finally, cement mechanical properties should not degrade during the whole steam injection process, i.e. when it is subjected to extremely high temperatures (up to 350 degC) for extended periods of time. Specifically in Canada, the majority of the steam injection wells are drilled in shallow sandstone formations. This requires the cement to have high flexibility to resist the stresses. Moreover, during steam injection, a reaction between the sandstone formation and the cement sheath may occur, impacting the cement matrix and hence changing its properties. This paper describes the application of a new thermally responsive cement for zonal isolation of heavy oil wells in Canada. This system is designed to have excellent strength, flexibility and thermal properties even upon interaction with sandstone formations. It minimizes the mechanical stresses exerted on the cement sheath during steam injection, thus reducing the risk of loss of well integrity. The numerical simulations performed with these long-term material properties (six months of exposure to 350 degC) for typical Canadian heavy oil wells conditions predict reliable and durable zonal isolation under these extreme conditions. These simulation results are confirmed by several field applications in wells which have not leaked after months of steam injection.

The drilling and completing of Infill wells (wells drilled amongst existing SAGD wells) is becoming common practice with many operators in North Eastern Alberta. These Infill wells pose numerous challenges that may not exist in the drilling and completing of a conventional SAGD well. In addition to conventional challenges such as lost circulation that need to be safely managed to have a successful completion strategy, the Infill wellbore has elevated temperatures and heat transfer rates due to contact with or close proximity to a steam chamber. There is no single, universal strategy used by operators to address and control these challenges, which require robust cementing solutions. Many clients are completing Infill cementing with expected bottom hole circulating temperatures (BHCT) ranging from 35°C to 100°C. This variation in clients’ BHCT results is due in part to the drilling, and more specifically, the circulation strategy used. Static periods of only a few hours can bring the effective temperature to that of the reservoir. As a conventional SADG strategy cannot be used for all wells, a specific blend design utilizing different technologies must be investigated. The large variations in bottom hole static temperature (BHST) and BHCT require complete understanding of the cement blend performance and its specific application. Cement blend designs that are applicable and can perform over a range of temperatures reduce the impact of these challenges. With the frequency of Infill cementing expected to increase, a greater understanding of the effective wellbore temperatures and the subsequent effective applicable temperature range of cement blends is needed.

There are many areas in the Western Canadian Sedimentary Basin that present challenges with surface casing vent flows (SCVFs). Substantial resources have been invested in understanding the causes of these SCVFs, developing remediation processes for wells impacted by SCVFs and creating products to prevent SCVFs from occurring. Despite these efforts, SCVFs remain an issue in the industry. The first priority of the energy company and service company is to operate in a safe manner with high regard for the environment. A secondary goal is to be cost efficient to maximize production. In order to satisfy these goals and priorities, working together to understand the challenges becomes critical. A clear understanding of the challenges provides an opportunity for the service company to tailor cement blend performance with the goal of eliminating the presence of SCVFs and reducing the costs associated with the remediation process. This paper presents a case study in the Celtic field, located approximately 80 kms northeast of Lloydminster, Saskatchewan, Canada. A higher frequency of SCVFs was observed in the wells when increased bottom circulating temperatures, influenced by a nearby active steam chamber, were reported while drilling. At the elevated temperatures, cement blend modifications were made to allow for adequate placement with the new wellbore parameters. The cement blend underwent a review and optimization process with respect to the new wellbore parameters. Findings showed that a substantial difference between the circulating and gas formation temperatures created ideal conditions for SCVFs to occur. The prolonged setting of the cement at low temperatures was believed to be the main challenge to overcome. A unique cement additive was used to accelerate the setting of the slurry at relatively low temperatures while ensuring it would still be pumpable in a high temperature environment. After incorporating the new additive into the cement blend, the operating company immediately saw an elimination of the SCVF in subsequent wells. This paper will review the steps taken to reduce and eliminate SCVF issues in the Celtic area, some parameters and characteristics of a well that impact SCVF, and steps that can be taken in the cement blend design to mitigate SCVF issues.