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Abstract

Cyclic steam stimulation (CSS) is an effective method to recover extra heavy oil but it achieves a relatively low recovery factor (~26% before economic limit is reached) and is less energy efficient with higher emissions intensity than that of conventional oil production. After it reaches its economic limit, it remains unclear what is the follow-up recovery process where the energy and emission intensities can be minimized. Here, a detailed examination of the Liaohe extra heavy oil CSS and continuous Steam Injection Gravity Drainage (SIGD) operations is conducted to examine their energy and emission intensities. Further analysis is conducted by using detailed geological and reservoir models and a history match of the CSS and SIGD operations. The results reveal that CSS is an effective thermal recovery method to initiate production from extra heavy oil reservoirs and that SIGD using infill wells is an effective post-CSS recovery process to produce a significant fraction of the remaining oil from the reservoir. For the reservoir studied, the steam-to-oil ratio (energy efficiency) and emissions intensity of SIGD is slightly worse than that of the initial CSS operation.

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... The third stage is a depleted development process, output initially reaches a peak rate after well opening, and then rapidly decreases with the decrease of temperature and pressure [20,21]. Therefore, in the later stage of CSS, the water content increases rapidly, the oil recovery decreases rapidly and the thermal efficiency of steam is greatly reduced [22,23]. How to fully utilize the capacity of the thermal fluid and explore the reservoir potential without changing the production method has become an urgent problem in the practical application of CSS. ...
... For wells with no further oil recovery potential, they can be converted to other followup recovery methods [23]. The evolution of heterogeneity and its fundamental impacts on steam conformance and liquid production rate for different permeability and heterogeneity levels in the process of steam injection has not been fully understood, and the steam profile control strategies after steam channeling and the well-to-well fracture communication need to be optimized. ...
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Production performance of heavy oil deposits in Xinjiang oilfield developed by vertical-well cyclic steam stimulation (CSS) is increasingly challenged by reservoir heterogeneity, which is comprised of original sedimental heterogeneity and steam-induced heterogeneity. In order to understand the impacts of sedimental heterogeneity and high-speed steam injection to steam conformance, and strategies to maximize steam swept volume, a series of experiments were designed and implemented. Three-tube coreflooding experiments were performed to study the steam displacement dynamics under heterogeneous conditions, and a high-temperature plugging agent was developed. The coreflooding experiments indicate that the injection conformance deteriorates once the steam breakthrough occurs in a high-permeability tube, leaving the oil in the medium and low permeability tubes being surpassed. The optimized plugging agent could resist high temperatures over 260 °C and its compressive strength was 13.14 MPa, which is higher than maximal steam injection pressure. The plugging rate of high permeability core was greater than 99.5% at 220–280 °C with a breakthrough pressure gradient over 25 MPa/m. The field test validated its profile improvement feasibility with cyclic oil, 217.6% of the previous cycle. The plugging agent optimized in this study has significant potential for similar heterogeneous reservoirs.
... The low reservoir temperature (typically 7-15 • C) makes recovery of heavy oils in their natural state very difficult. Over the last 20-30 years, steam assisted gravity drainage (SAGD) (Butler 1998Edmunds 1999 and cyclic steam stimulation (CSS) (Ali 1994;Bao et al., 2016;Trigos et al., 2018) are the two most used commercial recovery processes for oil sands deposits in Alberta (Butler 1991;Ali 1994;Batycky 1997;Donnelly 2000;Bybee 2003;Jiang et al., 2009;Bao et al., 2017). However, steam based processes are energy intensive and emission of greenhouse gases (GHG) generated during steam generation is unfavorable given environmental impact concerns. ...
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With strong potential for improving productivity, economics, and efficiencies, data analytics and machine learning are rapidly emerging in the oil and gas industry. However, their application in heavy oil production is scarce. In this study, we use clustering methods to analyze the Kerrobert Toe-to-Heel Air Injection (THAI) project to understand the inter-relationships of production variables and seek for optimal operating strategy to maximize production rate. More specifically, we use the K-means, normal mixtures and hierarchical clustering methods to determine how operating parameters contribute to oil production. The results reveal that, at current operation mode, air injection rate is constrained for production maximization due to the balance between heat generation and cooling of combustion system by excess air supply. The results also provide insight for improved productivity from THAI suggesting that cyclic injection may improve process performance. The new insights demonstrate that data analytics can provide new understanding of recovery processes as well as potential process improvement.
... In recent years, the exploitation of heavy oil has adopted method of cyclic steam stimulation (CSS) [28]. Cyclic steam stimulation (CSS) is one of the effective methods for the recovery of crude oil which has high viscosity such as bitumen, heavy oil, etc. Cyclic steam stimulation is often the preferred method for production in heavy oil reservoirs that can contain high-pressure steam without fracturing the overburden. ...
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... Poly(ether ether ketone) (PEEK) (Figure 1(a)) is the most widely available of the PAEK family, has the largest production volume, and performs well in most sealing and connector applications that involve contact with drilling fluids and sour (sulfur containing) crude oil under high-pressure and high-temperature conditions. Despite its superior performance in many downhole applications, PEEK is not suitable for the highest temperature steam injection strategies that use cyclic steam stimulation, 15 steam flooding, 16 and steam-assisted gravity drainage 17 for recovery of heavy oils from oil sand formations. Steam injection conditions can be as extreme as 2200 psi and 350 C in order to heat heavy oil and reduce its viscosity, thereby facilitating recovery. ...
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Poly(aryl ether ketone)s (PAEKs) are promising materials for harsh environments, such as in high‐temperature steam applications. Here, the effect of high‐temperature steam on the crystallinity and mechanical properties of existing poly(ether ether ketone) (PEEK) and PEKK(T/I) polymers is investigated. Differential scanning calorimetry (DSC), wide‐angle X‐ray scattering or diffraction (WAXD), and dynamic mechanical analysis experiments show these materials undergo significant crystallization and reorganization after prolonged exposure to steam and suffer from embrittlement. In addition, we show that xanthydrol‐based crosslinks can provide the dimensional stability and stabilize the PEKK crystal structure. Mechanical tests demonstrate that the ductility is preserved for longer exposures to steam compared to neat PEKK, whereas DSC and WAXD data indicate xanthydrol crosslinks effectively stabilize the crystal structure against steam‐assisted crystallization. © 2019 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019, 136, 47727.
Conference Paper
NCG is increasingly being co-injected with steam in heavy oil production systems to reduce heat loss and greenhouse gas emissions, as well as to maintain reservoir pressure. Given increased use of NCG co-injection, the validity of conventional subcool models must be revisited since they assume that the steam chamber is comprised of water alone. The current study makes modifications to the pure-steam hydrostatic subcool model, as well as the Yuan & Nugent (2013) subcool model to account for the presence of NCG in the steam chamber. Using typical values from the Athabasca oilfield, the study then compares the liquid-height predictions made by the original and modified models and proposes rules-of-thumb that correct for the presence of NCG. In general, increasing NCG in the steam chamber results in a reduction in subcool relative to pure steam. According to modified hydrostatic model, to achieve a liquid-pool height equal to that of pure steam injection, the subcool must be increased by 0.60K per 1% increase in the vapor-phase molar fraction. In contrast, over a wide range of production rates and drawdowns, the modified Yuan & Nugent (2013) model predicts that to achieve a liquid-pool height equal to that of the pure steam case, the subcool must be increased by 0.66K per 1% increase in the vapor-phase molar fraction. Despite the rule-of-thumbs being qualitatively in line with expectations, they suffer from the inability to accurately calculate subcool from field data. The final section of the paper reviews limitations of subcool as a well performance metric and proposes an alternative method of assessment that relies on data that are more readily available to operators.
Article
Cyclic in-situ combustion (ISC) is a novel process with great potential for thermal enhanced oil recovery (EOR). In this study, a 3D physical simulation experiment of cyclic ISC after cyclic steam stimulation (CSS) was carried out for the first time. The mass loss during heavy oil oxidation was studied by thermogravimetry (TG) and the preheating temperature of sandpack was determined by differential scanning calorimeter (DSC). The oxidation process of heavy oil in a porous medium was investigated by a heavy oil static oxidation experiment. The development characteristics and EOR mechanism of cyclic ISC after CSS were studied through 3D physical simulation experiments and the characteristics of the coking zone was studied by scanning electron microscope (SEM) and computed tomography (CT). The results of the thermal analysis indicate that three different regions were observed with increasing temperature: low-temperature oxidation zone (LTO), fuel deposition zone (FD), and high-temperature oxidation zone (HTO). When the temperature reaches 480°C, the mixed oil sand has the most exothermic effect and the high-temperature oxidation reaction is the most vigorous. The results of the 3D physical simulation show that steam channeling and steam overlay in CSS reduced the swept volume of steam and heat usage rate. During the cyclic ISC, the oil bank can overcome the heterogeneity of the oil reservoir caused by steam channeling and steam overlay, which makes the combustion front move forward smoothly. Cyclic ISC can greatly increase the temperature of the zone near the well, and upgrade the crude oil through cracking to reduce the viscosity of heavy oil. The foaming oil formed by the dissolution of flue gas improves the fluidity of the crude oil. The oil recovery of CSS is 19.3%, and the oil recovery of cyclic ISC increased by 13.2%. SEM and CT show that flake black solid coke was attached to the surface of the sand at the coking zone. The coking zone is a porous medium structure with a porosity of 35.14%, which has little effect on the oil recovery in the process of cyclic ISC.
Article
Steam injection is the most popular used method in recovering heavy oil reservoirs. Many researchers were engaged in enhancing oil recovery (EOR) methods by using various well configurations. Laboratory experiments and field applications have verified the feasibility of extra-heavy oil recovery by steam injection using vertical injector -horizontal producer. It was also referred to as a steam assisted gravity drainage (SAGD) process. However, the characteristic of steam chamber growth and production performance during the vertical injector-horizontal producer steam injection process have not been fully understood. In this study, a 3D physical model was constructed to investigate the mechanisms of the steam injection process using vertical injector-horizonal producer. Numerical simulations were also conducted to verify the laboratory experiment and field application. In the aspect of steam chamber growth, the results revealed that three stages were included during the steam injection process. In the aspect of developing mechanisms, it can be divided into steam flooding and gravity drainage stages. Moreover, the results show that about 43.9% of original oil in place (OOIP) was produced in the gravity drainage stage. In addition, subcool showed significant difference in steam flooding and gravity drainage stages. The temperature distribution mode of the horizontal producer was analyzed and proved to be a significant factor that influences the production performance. Sensitivity analysis by using numerical simulation demonstrated that oil viscosity is the dominant factor that impact the production performance. The results guided the development of pilot test area in Xinjiang Oilfield, China. The study can provide a clearer understanding of the vertical injector-horizontal producer steam injection process in recovering heavy oil reservoirs.
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Steam fracturing as done during cyclic steam stimulation is an effective thermal process for initiating recovery from viscous oil reservoirs such as oil sands reservoirs found in Alberta, Canada and Liaohe, China. A key component of these processes is the ability to inject high temperature steam into the formation to fracture it which in turn raises its permeability and mobilizes the oil by lowering its viscosity. The dynamics of steam fracturing are not fully resolved especially how steam fingers into the reservoir and how its state changes as heat losses occur from the injected steam. The results of this study reveal that steam condensate, pressurized by the steam vapour upstream, fractures the formation. The results also show that dilation of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below that of the case where no dilation occurs.
Article
China has significant heavy oil deposit of more than 1.9 billion tons of oil reserve in place (OOIP) with four major heavy oil producing areas, which are Liaohe Oil Field, Xinjiang Oil Field, Shengli Oil Field and Henan Oil Field. China has many types of heavy oil reservoirs such as single-layer, multi-layer, thick-blocked reservoir with wide range of oil viscosity from 100 cp to 100,000 cp and depth from 200m to more than 2000m. Heavy oil has been produced for many years in China. However, the commercial heavy oil development was initial in 1982, when the first cyclic steam injection pilot test was successful in Liaohe Oil Field. In 1993, the heavy oil production had reached 10 × 106 tons per year. From then on, the annual heavy oil production has kept the level of 10~13 × 106 tons for more than 10 years. The development manners of heavy oil reservoir are cyclic steam stimulation (CSS), steamflooding, waterflooding. CSS is the major manner, widely used in traditional-heavy, extra-heavy and super-heavy oil reservoir in China with the annual production more than 85% of total heavy oil production. CSS has become a mature industry technology, which includes high-efficient steam injection, artificial lifting, sand controlling, re-entry drilling, steam surveillance and so on. Steamflooding is successful in developing shallow heavy oil reservoir such as Karamy oil reservoir, including high-temperature profile conformance, surveying and steam measurement technologies. This paper reviews the distribution of heavy oil resources, status of heavy oil development, trends and also the challenges faced in improving utilization of the resources in China.
Article
Currently, to mobilize and produce bitumen from Athabasca oil sands reservoirs, Steam-Assisted Gravity Drainage (SAGD) is the method of choice. SAGD, requires large amounts of energy and emits significant volumes of greenhouse gases to the environment. Here, we discuss the thermal efficiencies, energy balances, and emissions of SAGD. While the world’s heavy oil and oil sand resource is large, average recoveries from heavy oil and oil sand reservoirs are typically low, ranging from 5% to 15% for cold heavy oil production and from 25% to 60% percent for steam-based in situ processes. This is for two reasons: firstly, geological heterogeneity and secondly, ubiquitous large scale fluid property heterogeneities are common on a range of spatial scales. Thus, there is a strong motivation to develop better recovery processes with lower energy and emission intensities. The thermal efficiencies, energy balances, and emissions of SAGD show a very wide range of field performance for the current thermal recovery projects in Alberta, with earlier pilots being more successful. The data suggests that at the extreme, some operations are actually not net energy generating with injected energy via steam, exceeding recovered chemical energy in recovered oil. Differential pricing of oil and natural gas, the main steam generating fuel, still permits these extreme cases to be economically profitable due to low natural gas prices. In all cases, carbon dioxide intensity is high.
Article
Du 84 block of Shu-1 area in the Liaohe Oilfield is located in Panjin city of Liaoning province of China. The production formation, Guantao, contains extra heavy oil with a depth of 530-640 meters. The reservoir is characterized in thick pay, high permeability and very active aquifer. The dead oil viscosity is 230,000 mPa.s at 50 °C. Although Cyclic Steam Stimulation (CSS) process using vertical wells has been applied successfully in producing oil from the reservoir, the anticipated ultimate oil recovery is less than 29% of the original oil in place (OOIP). To enhance oil recovery beyond that of the CSS, physical and numerical modeling studies were carried out. The Steam Assisted Gravity Drainage (SAGD) process using the combination of the vertical wells and horizontal wells was proposed to be the follow-up process to CSS. Additional 27% recovery is anticipated with the proposed follow-up process. This gives a total recovery of 56%. A pilot with four horizontal producers was implemented in the field. CSS was used initially in the horizontal wells for establishing the communication with the surrounding vertical wells. The pilot was then converted successfully to SAGD operations with horizontal wells as continuous producers and some of the surrounding vertical wells as continuous injectors. A total of 44,500 tonnes of oil has been produced so far during the last 12 months of SAGD operations. The field implementation process and pilot performance as well as the challenges with this project are presented in this paper. Introduction This paper is the continuation of the work presented in 2003's CIM conference [1] . In that paper, a field pilot was proposed for testing Steam Assisted Gravity Drainage (SAGD) as a followup process to CSS based on the reservoir modeling work and feasibility studies. Two field pilot projects were constructed in 2003 in Du 84 block of Su-1 area in Liaohe oilfield. One pilot is producing from the Xinglongtai formation and the other one is producing from the Guantao formation. The pilot in the Guantao formation was converted to SAGD operations in early 2005 and the field results are encouraging. This paper is going to report the field performance for this pilot. Steam Assisted Gravity Drainage (SAGD) process, which was described by Dr. R.M. Butler in the late 1970s [2] , has been applied successfully for the production of bitumen and heavy oil since it was tested in the Underground Test Facility (UTF) in the Fort McMurray oil sand, Alberta, Canada [3]. Several commercial projects have been implemented in the field in Canada since then. Liaohe oilfield constructed the first SAGD pilot in China in 1996 in the Xinlongtai formation, which contains extra heavy oil at a depth of 750 meters deep from the surface. The pilot consisted of one stacked well pair and was operated for about one year and half. The suspension of the pilot test was due to (1.) not sufficient lift capacity provided by gas lift system; (2.) difficult in communication resulted from too large vertical separation between the injector and producer.
Article
Numerical simulation method is applied to study the effects of some parameters on steam overriding, including oil layer thickness, crude viscosity, vertical/horizontal permeability ratio, perforation method, etc. Therefore, the change pattern of steam overriding is obtained and the technical conditions for steam overriding are pointed out. Field test results indicate that by taking some measures, such as adopting the "uphole?? perforation, profile control, separate or selective steam injection, vertical and horizontal well combined SAGD, etc., the uneven producing of the reservoir vertically due to steam overriding can be further decreased. Moreover, these measures play an important role in increasing oil recovery ration during the later production period of CSS. The successful application of these techniques will provide theoretical support and technical guarantee for the production of similar super heavy oil reservoirs in the world during the later production period of CSS. Keywords: Steam overlay; CSS; Separate or selective steam injection; Vertical and horizontal well combined SAGD Introduction Liaohe oilfield as China's largest heavy oil field, with an annual heavy oil production of 8 million tons, mainly adopts CSS production pattern. At present, most of the CSS development blocks in Liaohe oilfield, have entered the later production period and gradually expose a series of development conflicts and technical problems. Of these, in CSS development in high porosity, high permeability and super heavy oil reservoirs such as Du84, steam overlay phenomenon is particularly prominent. Therefore, it is necessary to study on the effect factors and laws of steam overlay, in order to propose targeted solutions. At the same time, for the acceleration of production decline rate during the later production period of CSS, researches into production methods conversion and its supporting technology are necessary.
Article
Guan-tao oil layer of Shu 1 Block in Liaohe oilfield is a medium deep and extra heavy oil reservoir, which has high porosity and high perm with edge water. In 2001, cyclic steam stimulation was applied with square well pattern and well-space 70m. After 9-10 cycles the stimulation development effect deteriorated and the degree of reserve recovery was only about 15%. To seek development method of extra heavy oil reservoir and improve the entirety recovery ratio of this block, after the feasibility research on SAGD technology in Guan-tao oil layer was finished, horizontal wells were infilled between vertical wells and 4 SAGD pilot test well groups combining vertical wells with horizontal wells were conducted Three cycles of cyclic steam stimulation to preheat the formation and decrease pressure were proceeded and the 4 well groups had produced for 1 year after converted to SAGD. Daily oil production capacity of single horizontal well increased from the initial 20-40t/d to 70-80 t/d after the multiple adjustment of the injection-production parameters. Preferable period effect was accomplished and the test provides good guide for same medium deep and extra heavy oil reservoir to change their development methods.
Article
Imperial Oil Resources Limited began pilot experimentation with Cyclic Steam Stimulation (CSS) at Cold Lake in 1964 and followed this with commercial application in 1985. Since that time an extensive amount of experimental data and operating experience has been acquired which has resulted in the continual evolution of steaming and operating strategies for CSS. Optimization of the many process variables involved in CSS is complex due to their interdependency. The optimization of steaming and operating strategies has advanced significantly with commercial development and continues to evolve as the CSS process matures and the reservoir reaches more advanced stages of depletion. This evolution has focussed on steam strategies to manage interwell communication and increase areal conformance, and operating strategies to maximize the efficiency of producing mobilized bitumen which lies at ever increasing distances from the wellbore. The continued success of CSS in Cold Lake is dependent on the continued improvement of these steaming and operating strategies.
Article
The Pikes Peak steam pilot was initiated in 1981 to evaluate cyclic steam recovery in a Lloydminster (Canada) channel sand reservoir containing 12°API oil with a gas-free viscosity of 25 000 mPa.s (25,000 cp) at initial reservoir conditions. Cyclic steam response has been very good, but the economics worsen after 20 to 30% of the original oil-in-place (OOΙP) has been recovered. Based on the reservoir's excellent permeability (5 to 10 darcy) and on frequently observed interwell communication, a 3 hectare (7.4 acre) inverted seven-spot pattern was converted to steam drive in 1984. This pattern was used to evaluate various steam injection rates, flow diverting foam, and stimulation of lagging producers. Tritium tracer test data, profiles from two temperature observation wells, and a post-steam core were collected and evaluated; and numerical modelling studies were also initiated. Field data from the first pattern and forecasts from the numerical modelling studies were used to refine the conversion criteria. In these criteria were used to select two additional patterns for conversion, and both have yielded excellent performance. Four additional patterns have been converted to drive since 1986, and steam drive currently contributes approximately half the project's total production. Studies are underway to further refine the cyclic-to-drive conversion criteria, evaluate the effects of pattern surroundings, develop methods to improve vertical and areal sweep, and develop a post-steam recovery strategy.
Article
A history-matched, 2D, single-well numerical model was used to evaluate the contributions of four key drive mechanisms to early cyclic-steam-stimulation (CSS) oil recovery at Cold Lake, Alta. Formation compaction was found to be by far the dominant producing mechanism. Solution-gas drive was the most important of the remaining mechanisms. Fluid expansion had a relatively minor role. Gravity drainage accounted for little of the oil produced in the first two cycles, but increased in importance in subsequent cycles.
Article
The Cold Lake reservoir is an unconsolidated sand containing extremely viscous bitumen. Steam injectivity during cyclic steam stimulation can be achieved only by injecting at pressures high enough to mechanically fail the formation. Simulation of the complex fracturing and reservoir deformation behavior that results is very challenging. In addition, the reservoir exhibits water-oil relative permeability hysteresis, which must also be properly modeled. This paper describes enhancements made to a thermal reservoir simulator to incorporate these Cold Lake physics. Rigorous geomechanical modeling is not economical, so an empirical approach has been developed that is consistent with the behavior of unconsolidated sands. Fracturing is modeled by allowing the permeability in a. plane of gridblocks to increase rapidly when the pressure exceeds a specified fracture pressure. Reservoir deformation in all blocks is modeled by first allowing dilation, during which porosity increases when the pressure exceeds a specified failure pressure. Subsequent pressure decline causes the reservoir to recompact, and porosity decreases. However, recompaction is not the reverse of dilation, and a fraction of the total dilation is permanent. While all gridblocks have similar deformation properties, the history of each individual block plays a role in determining its exact behavior. This geomechanical representation allows the simulator to match field observations that are otherwise difficult to reproduce, including injection pressures, flowback times, and production pressures. Also, the model appropriately handles the recompaction process which provides drive energy in the Cold Lake reservoir. The water-oil relative permeability hysteresis model is based upon laboratory measurements. Bounding imbibition and drainage curves are input; gridblock relative permeabilities, which depend upon both saturation and saturation history, are determined such that calculated values always lie on or between the bounding curves. The hysteresis model makes it possible to use laboratory-derived relative permeabilities when simulating cyclic steam stimulation and still match field water-oil ratios.
Article
The Cold Lake project, located in Alberta, Canada, is the world’s largest heavy oil in situ thermal development, with production of about 24,000 m3/d (150 kB/d) of oil from more than 4500 wells. In 2009, Cold Lake produced its one billionth barrel (160 million m3) of heavy oil. The world class Cold Lake hydrocarbon resource is characterized as a bitumen deposit, featuring in situ viscosities in excess of 100,000 mPa-s. Early depletion plans envisioned a thermal recovery process similar to the steamflood technologies employed to recover heavy oil in California’s San Joaquin Valley. The order of magnitude difference between Cold Lake and California in-situ viscosities, however, severely limits steam injectivity below fracture pressure, necessitating the development of a Cold Lake specific cyclic steam stimulation (CSS) process throughout the 1980s. Continual process optimization combined with infill drilling has resulted in a progressive increase in expected bitumen recovery from 13% to greater than 40% of effective bitumen in place (EBIP). A multi-disciplinary reservoir management effort conducted over the last several years has provided the view that Cold Lake recovery levels may potentially be increased to over 65% by adapting steamflood principles to mature CSS areas of the reservoir: reservoir simulation was used to define the steamflood opportunity’s technical and economic viabilityan extensive selection process based on several criteria was used to select an appropriate field trial locationtrial plans were reviewed with experts with California steamflood experiencea Cold Lake steamflood field trail was designed, implemented and successfully operated for three years As cyclic process efficiency declines due to lack of steam confinement, steamflood technologies become an attractive recovery scheme in mature Cold Lake reservoir by capitalizing on large scale inter-well communication while focusing on gravity drainage: trial results to date are encouraging and in agreement with performance predictionssuccess to date has benefited from the evaluation of prior trails at Cold Lake, review of global steamflood analogs and extensive reservoir simulation efforts prior to field trial design and implementationsteam confinement is a significant but manageable operational challenge
Article
For over 30 years, Imperial Oil Limited has been pioneering the extraction of a very heavy grade of oil known as bitumen from the Alberta oil sands in the Cold Lake area. For close to 10 years, a world scale commercial project has operated, employing a thermal recovery process known as "cyclic steam stimulation" (CSS). This process involves alternating periods of steam injection and production, both through the same wellbore. The Cold Lake operation faces two challenges not typically experienced by conventional operations. First, substantial costs are incurred to generate steam, and treat water. Also, bitumen sells for less than light sweet crude. Consequently, margins are tight, and continuous unit cost improvements essential. This paper describes the Cold Lake operation along with many of the innovations that have led to a one-third reduction in operating costs over the past decade.
Article
In cyclic steam stimulation (CSS), steam is injected above the fracture pressure into the oil-sands reservoir. In early cycles, the injected steam fractures the reservoir, creating a relatively thin dilated zone that allows rapid distribution of heat within the reservoir without excessive displacement of oil from the neighborhood of the wellbore. Numerical reservoir-simulation models of CSS that deal with the fracturing process have difficulty simultaneously capturing flowing bottomhole-pressure (BHP) behavior and steam injection rate. In this research, coupled reservoir-simulation (flow and heat transfer) and geomechanics models are investigated to model dynamic fracturing during the first cycle of CSS in an oil-sands reservoir. In Alberta, Canada, in terms of volumetric production rate, CSS is the largest thermal recovery technology for bitumen production, with production rates equal to approximately 1.3 million B/D in 2008. The average recovery factor from CSS is between 25 and 28% at the economic end of the process. This implies that the majority of bitumen remains in the ground. Because the mobility of the bitumen depends strongly on temperature, the performance of CSS is intimately linked to steam conformance in the reservoir, which is largely established during steam fracturing of the reservoir in the early cycles of the process. Thus, a fundamental understanding of the flow and geomechanical aspects of early-cycle CSS is critical. A detailed thermal reservoir- simulation model, including dilation and dynamic fracturing, was developed, with the use of a commercially available thermal reservoir simulator, to understand their effects on BHP and injection rate. The results demonstrate that geomechanics must be included to accurately model CSS. The results also suggest that the reservoir dilates during steam injection as the result of increases in reservoir temperature, which lead to thermal dilation and higher pore pressure.
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