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.

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.

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.