Diagnostic Fracture Injection Tests (DFITs) provide a critical piece of information on the competency of the top seal for injection projects and are therefore essential for Subsurface Containment Assurance (SCA) and Maximum Operating Pressure (MOP) determination. Results of DFITs provide the best estimate for the minimum principal stress component, which is a major input for tensile and shear failure tolerance analysis. Therefore, best practices in execution and analysis of DFITs is extremely important for safe and successful operations. Numerous DFITs have been conducted over the past ten years in Surmont to assess the integrity of the caprock and determine the maximum allowable steam injection pressure. A combination of surveillance and coupled reservoir-geomechanics simulations have been utilized to maintain a minimum of 20% safety factor for caprock failure. The tangent analysis method for determining fracture closure pressure has been extensively used in the past decade for DFIT analysis in the industry [ 1 and 2 ]. The validity of this method has been challenged recently through more rigorous modeling of the hydraulic fracturing process and field observations. An alternative analysis method referred to as the compliance method has been proposed and successfully used in many cases [ 3 ]. In the past few years, we have demonstrated the potential to safely increase the maximum operating pressure and its impact on production, through extensive caprock integrity analysis in Steam Assisted Gravity Drainage (SAGD) operations [ 4 and 5 ]. In this study, the DFITs carried out in Surmont were revisited to assess the potential impact of characterizing in-situ stresses with improved accuracy on maximum allowable injection pressure and ultimately production uplift. The analysis shows higher minimum horizontal stresses in the caprock are supported by field observations, which could potentially allow for higher injecting pressure and close to five percent additional production in the two selected SAGD pads.

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.

A noteworthy caprock failure occurred on the Joslyn Steam Assisted Gravity Drainage (SAGD) project in 2006 that continues to have a significant impact on the approval process for future SAGD projects. Two major reports were released by Total E&P Canada Ltd. as operator and Alberta Energy Regulatory (AER), respectively. A number of potential mechanisms were postulated within those studies, but without a definitive resolution. Inclusion of a fractured medium in the assessment of caprock integrity has not been extensively studied for detection of failure modes. The objective of this paper is to explore the effects of existence of discontinuities (e.g. fractures or fissures) in caprock, loading conditions, and steam chamber evolution, on surface heave, joint normal and shear displacements. Different modes of failure under various scenarios are presented for fissured and non-fissured caprocks. In this paper, a distinct element code was utilized to simulate the possible mechanisms of caprock failure during SAGD operation with various fracture sets in the Clearwater Formation caprock. Three-dimensional numerical models, including caprock and overburden, were simulated under different load conditions to evaluate the impact of steam injection pressure. The lower bound for maximum operating pressure (MOP) was based on the current AER formula and the upper bound was the injection pressure prior to caprock failure. Multiple realizations of fracture network in caprock were executed to reflect various geomechanical and geometrical properties of fractures. The results were compared with a previous study performed with the assumption of a continuum medium for a non-fissured caprock. For upper bound MOP conditions, the computed maximum vertical displacements at the base of caprock for models assuming 1) no fractures, 2) low fracture intensity, and 3) high fracture intensity were 79, 74 and 68 cm, respectively. It was observed that an increase in fracture intensity results in a reduction in vertical displacement at the base of caprock as well as surface heave. These variations in behavior are significant and illustrate that the assumption of a non-fractured caprock (in caprock integrity studies) may lead to conservative estimates of steam containment and ultimately, underestimation of the risk for caprock failure. At the base of caprock and under lower bound MOP conditions, a few local shear failure zones occurred above the pressurized zone, while for upper bound MOP conditions, larger zones of both shear and tensile failures were computed. It was also noted that the existence of fractures could cause local shear failure in the caprock, even below AER mandated values of MOP. Lastly, the findings of this study, including geomechanical simulations, uncertainties, and risk associated with evaluating caprock containment of SAGD operations were compared with previous studies. The results offer significant insight into our geomechanical understanding of the process in order to avoid a potential caprock failure during thermal projects, as unfortunately was experienced in the Joslyn SAGD steam release incident.

Steam assisted gravity drainage (SAGD) is a widely used thermal recovery method. During steam injection in interbedded sands, the portion of the deposits above the vertical permeability barriers is likely not recoverable with current practices. This paper discusses some of the geomechanics and fracturing aspects of using multistage fracturing in SAGD operations in interbedded sands such as IHS, where the vertical permeability barriers impede the gravity drainage process. The first part of this work (to be presented in a separate manuscript) covered the reservoir engineering aspects of this method, where it was assumed that it is possible to successfully create vertical fractures in the oil sands and through shale layers. In this paper, the geomechanical challenges in implementing the method and after the start of operation are discussed, starting with a review of relevant hydraulic fracturing field trials in the oil sands. Some interface crossing criteria are reviewed and the extended Renshaw and Pollard criterion is used to study fracture propagation through sand-shale interfaces. These results are then compared to results of a numerical simulation using a coupled reservoir-geomechanics-fracturing simulation software. It is shown that tensile hydraulic fractures can be created in the oil sands, and fractures can cross sand-shale interfaces and be filled with desired concentration of proppant. It is shown that small but high conductivity fractures that are required for the success of the proposed method, can be generated by using currently available proppants and fluid systems. After start of the steam injection, the conductivity of the fracture might be reduced by various mechanisms such as proppant embedment. It is shown that the reduction due to embedment would not be significant at high range of proppant concentrations and also due to the low stress regime in the Alberta oil sands. Furthermore, the design considerations for various liner systems that can combine the fracturing process and the SAGD phase are discussed and a few new designs are proposed. Finally, a step by step roadmap for field implementation of this method is presented. The novelty and main contribution of this paper is the analysis and design considerations of the application of multistage fracturing in SAGD process in the field. Our results indicate that the field execution is feasible, and a field trial of the technique is justified.

19° API gravity oil with a viscosity between 150 to 200 cp is produced from the “El Corcobo Norte” and “Cerro Huanul” fields (550 active producer wells and 330 active injector wells) located in the Neuquen basin, Argentina. The reservoir is an unconsolidated sandstone reservoir that has been producing since 2005 by combining two techniques: cold heavy oil production with sand (CHOPS) and conventional waterflooding. Water injection began approximately one year after the start of production of oil, and while an excellent production response to the injection well was observed, the continuing sand production generated deep wormholes that allowed for direct communication between the injector and producer in some wells, resulting in the total loss of oil production. Beginning in 2011, different remediation techniques were tested from the injector wells to repair the “pipeline” to the producing wells, with variable results. The original remediation program consisted of two steps: 1) a treatment to reconstitute the porous matrix (TRPM) and 2) a conformance water-control treatment (WCT), which was not as effective and was eliminated in the following remediation treatments. TRPM allowed the operator to put back into production wells that had been shut in, and its design evolved to help reduce costs and continue the wells’ reactivation. To achieve an estimated ultimate recovery (EUR) factor of 50% (it was at 35% between the primary and secondary recovery), an injection project including an alkali, surfactant, and polymer (ASP fluid) treatment was implemented to improve the fluid sweep efficiency in a mature area of the field having high water cuts (85 to 90%). This project included drilling infill wells to go from an inverted seven-spot to a direct five-spot pattern, reducing the acreage from 60 to 20 acres (Ac). In 2013, the infill wells were completed without CHOPS; instead, a fracpack with proppant coated with a curable liquid resin (CLR) resistant to high pHs (i.e., the ASP fluids) was used to help prevent a possible collapse of the reservoir in the near-wellbore and entrapment of the progressive cavity pump when the ASP fluid front passed through as it would remove the residual oil that holds the sand grains together. To date, this fracpack treatment appears to have achieved the objective.

Hydraulic fracturing can be used in low-permeability heavy oil reservoirs for improving the production rate. It is challenging to achieve a high degree of fracturing fluid flow-back in low-permeability heavy oil reservoirs. This research investigates the application of a novel hyper-branched polymer fracturing fluid in low-permeability heavy oil reservoirs. A hyper-branched polymer, which has numerous end groups and possesses a special highly branched three-dimensional spherical molecular structure, is characterized by Fourier Transform Infrared (FTIR) spectrophotometer. Laboratory tests are conducted to evaluate the stability of viscosity at a given shear rate, temperature and shearing resistance, reversible cross-linking property, filtration property, and proppant-carrying performance of this hyper-branched polymer fracturing fluid. The degrees of core's formation damage are compared through conducting coreflood experiments, where the cores are treated with two fluids: the hyper-branched polymer fracturing fluid and guanidine gel fracturing fluid. The laboratory evaluation shows that the hyper-branched polymer fracturing fluid has good rheological characteristics, a high solubility in water, as well as good temperature and anti-shearing resistance. After being sheared for 90 minutes with the shear rate of 170 s −1 at 150°C, it can still be reversed to gel with high strength because of its reversible cross-linking effect. This fracturing fluid has a good antioxidant ability, which allows its basic fluid to be exposed to air for 48 h without viscosity reduction. Therefore, the basic fluid can be prepared as spare fluid in a large amount, significantly improving job efficiency on site. Meanwhile, field applications in some wells in China show that: the friction of this fracturing fluid during fracturing is about 30%-50% to that of the normal guanidine gum fracturing fluid. Thus it has an ultra-low friction feature. The flow-back rate of the fracturing fluid can reach as high as 80%. Besides, its cost is about 75% to that of the normal guanidine gum fracturing fluid, making it a clean and cost-effective system. The fracturing fluid prepared with hyper-branched polymer possesses outstanding technical advantages as well as good cost effectiveness, implying a promising application in the large-scale fracturing stimulation of low-permeability heavy oil reservoirs.

The Alberta Energy Regulator (AER) requires mini-frac tests to be performed on thermal or polymer injection projects as part of the licensing process. Mini-fracture closure stress in the cap rocks is the key item used in determining the maximum operating pressure (MOP) for injection wells. The MOP has a significant impact on the economics of the project. This paper will establish a physics based interpretation method that covers all injection/fall-off mini-frac tests. In the field, mini-frac tests are typically performed with multiple injection/fall-off cycles (usually 5 to 7 cycles) on each zone. Multi cycle testing is unique to the oilsands and their associated cap rocks. Multiple zones are also tested in a well, in both pay intervals (typically McMurray sands) and cap rocks (Clearwater shales etc.). Each cycle is analyzed for closure events and hopefully a consistent stress is found for each zone. Industry currently faces a conundrum as there is no agreement among analysts as to how to interpret these tests. As a result, reports submitted to the AER follow different methodologies. This may partially explain the wide range of reported closure stresses within individual basins. This paper will show using field mini-frac data that traditional interpretation techniques can lead to ambiguities/incorrect interpretations. These issues can be overcome by using a pressure transient analysis (PTA) based interpretation approach. PTA has a long history of analyzing injection/fall-off and production/build-up tests where the rock fabric does not change during the test. The PTA interpretation methodology has remained remarkably consistent over the past 25 years. It can be summarized as follows: first identify flow regimes with a special kind of derivative plot, and second use flow regime specific specialized plots to calculate formation properties. This paper will show that PTA can now also handle dynamic fracturing (i.e. mini-fracturing) and all of its associated special cases; which include pressure dependent leak-off, height recession/transverse storage and tip extension. Mini-frac analysis is now just a sub-set of the larger PTA methodology. It has the added advantage in that a rules based procedure can be established for the entire interpretation workflow.

Cyclic steam stimulation (CSS) is a commercial in situ recovery method that involves injecting steam into formations at high pressure to reduce the viscosity of heavy oil and bitumen. The injection pressure is typically above the reservoir fracture pressure to induce fractures, which can improve reservoir permeability and fluid mobility. Geomechanics and heterogeneities near a well significantly affect reservoir fracturing, particularly under thermal conditions. In addition, oversimplified descriptions of fracture geometry may fail to represent actual reservoir performance. Thus modeling near-well flow effects coupled with geomechanics is essential for detailed large-scale thermal simulations with fractures. Conventional methods have exhibited limitations in capturing interactions among wellbore/near-well flow, geomechanics, and fluid flow during CSS development. Therefore, flow/stress/near-well flow coupling under different fracture geometries is investigated in this study. A facies-controlled geostatistical model is first constructed for a Cold Lake reservoir to obtain more reliable results. A fully coupled model is further generated from this geological model. After local grids near wells are refined, we construct different fracture geometries by changing the fracture length and direction. In this study, uncertainty analyses on fracture geometry near the vertical wells are performed. The simulation results show that omitting geomechanics and wellbore modeling increases oil recovery. Moreover, oversimplified fracture geometry with simple planes overestimates an oil rate. Furthermore, fractures with complex geometries and geomechanics exhibit high conductivity and provides effective channels for steam and bitumen but at the same time, it may cause steam channeling and decrease the efficiency of steam injection.

In Cyclic Steam Stimulation (CSS), steam is usually injected above fracturing pressure into oil sands to achieve desired injectivity; thus fractures are generally induced. The induced fractures will affect heating and flow patterns and thus affect the choice of well spacing and steam injection strategies. Therefore, it is critical to evaluate fracture length for successful CSS projects. Transient Temperature Analysis (TTA) is a technique which uses well-bore transient temperature data to estimate reservoir/wellbore characteristics. This paper discusses the feasibility of using TTA to evaluate the lengths of steam-induced fractures in cold lake oil sands by using wellbore transient temperature data in the soaking period of CSS. Numerical simulation model was first established based on history matching production data of a typical well in cold lake oil sands. Then the effect of different fracture lengths on temperature response in soaking phase was examined. Simulation results shows, in the middle and later period of soaking phase, linear relationships are found when temperature drop versus square root time are plotted. However, the correlation between fracture length and the slope is not clear. Based on the heated zone size and heated zone shape analysis at the very first moment of soaking phase, it is found the combined impact of reservoir permeability, reservoir thermal conductivity and fracture length determines the shut-in temperature response, which can be reflected on the slopes of the plots, with certain injection volume. But the qualitative representation of slope using fracture length, permeability and thermal conductivity cannot be found based on the results of finite difference based simulator. Aside from Finite difference method, simulation tools based on other numerical methods can be attempted to conduct TTA to evaluate the lengths of steam-induced fractures in CSS process.

This paper describes a numerical investigation of hydraulic fracturing in oil sands during cold water injection. Previous studies have shown that hydraulic fracturing in unconsolidated or weakly consolidated sandstone reservoirs is highly influenced by the low shear strength of these materials and is quite different from competent rocks. As such, existing classical hydraulic fracture models are incapable of predicting the fracturing process of weak sandstone reservoirs. This paper presents a numerical tool to simulate hydraulic fracturing in oil sands and weak sandstone reservoirs. A smeared fracture approach is adopted in the simulation of tensile and shear fracturing in oil sands. The model incorporates various phenomena expected in hydraulic fracturing, including poroelasticity and plasticity, matrix flow, shear and tensile fracturing and concomitant permeability enhancement, saturation-dependent permeability, stress dependent stiffness and gradual degradation of oil sands due to dilatant shear deformation and strain localization. The results of the hydraulic fracturing simulation indicate that poroelasticity as well as shear fracturing can result in breakdown and propagation pressures larger than the maximum in-situ stress. Applying such pressures in fracturing operations can compromise the caprock integrity. It is found that at injection pressures below the vertical stress, saturation-dependent relative permeability and the development of shear fractures in the reservoir highly influence the injection response.

This paper describes a geomechanical work program carried out in Karamay heavy oil field, Xinjiang Province, China. Three mini-frac tests were conducted to measure the in-situ minimum stresses in the reservoir sands, shale interbed and caprock shales. Geomechanical triaxial tests under room- and high-temperature were completed to investigate the geomechanical properties of the reservoir sands. These works were motivated by repeating the success experienced in Alberta oilsands reservoirs which proactively use geomechanics to enhance the in-situ thermal recovery. One particular technology, i.e. using geomechanical dilation mechanism for early SAGD start-up was successfully demonstrated on one SAGD well pair in the Karamay reservoir. The results from the mini-frac tests and laboratory tests are presented and compared with the oilsands reservoirs in Alberta, Canada. Differences were discovered. Petrophysical and mineralogical measurements were made and geological origins are sought to explain the difference. Furthermore, relevant results from the dilation start-up demonstration are also shared to the end of this paper. Such success has proven again that geomechanics is equally important in the optimization of in-situ thermal stimulation of the heavy oil reservoirs in Karamay heavy oil field.

The Devonian Grosmont Formation is a bitumen saturated carbonate unit located in northern Alberta. It is considered to be Canada's second largest unconventional oil resource after the McMurray Formation oil sands. Production from the Grosmont Formation has been tested by a consortium of Unocal, Canadian Superior, AOSTRA, Chevron and other companies between 1970's to 1980's with some success and significant learning. Since 2010, Laricina Energy Ltd. and Osum Oil Sands Corp. have started a new wave of testing thermal recovery processes for the Grosmont Formation using horizontal wells. The Grosmont C carbonate reservoir contains vugs and fractures at multiple scales, and thus has a different porosity and permeability network than the clastic oil sands. This paper describes a numerical simulation approach to history matching the performance of one of the pilot wells in order to better characterize reservoir properties such as fractures and vugs at multiple scales and their interactions with the rock matrix. CMG's STARS dual porosity dual permeability module was used to simulate this complex system. The results of the simulation suggest that small-scale vugs should be combined with the matrix in order to obtain a better history match of the reservoir and production performance. Parameters describing fracture properties have become critical not only in matching the well behavior, but also in matching reservoir thermal responses. Advantages, limitations, and recommendations for using a dual porosity and dual permeability model for understanding a multiple-scale porous and permeability system are also discussed.

A significant caprock failure occurred on the Joslyn SAGD property in 2006, which has had a wide impact on the approval process for future SAGD projects. Two reports were released by the Alberta Government: "Total E&P Canada Ltd., Surface Steam Release of May 18, 2006, Joslyn Creek SAGD Thermal Operation, ERCB Staff Review and Analysis, February 11th, 2010" and "Summary of Investigations into the Joslyn May 18th, 2006 Steam Release, Total E&P Canada Ltd.". The latter report is very large. A number of potential mechanisms are postulated without definitive resolution. The most likely failure suggested involved transmission of fluids up a 50,000 mD chimney and a pancake shaped lens of high pressure steam that resulted in a shear failure of the caprock. The author believes that this scenario is unlikely from a geological and heat transfer perspective. There are other anomalies. Peak stresses in most caprock coupled reservoir-geomechanical simulations normally peak between 3 to 7 years after start-up. However, the Joslyn failure occurred immediately after conversion from partial SAGD to full SAGD, in which the producing well was killed and a PCP pump was run. There are other issues that should be considered that include: How hydraulic fractures are initiated and propagated. The literature shows us: computer design programs that predict fracture propagation and shape, analytical solutions that also show expected fracture morphology; and, physical examples which have been dug up or cored In addition the geological record provides excellent analogue information on the morphology of high pressure intrusions. These various types of data will be compared to the observed morphology derived from the 3D seismic. Earlier work by Edmunds and Good has shown that extremely transient conditions exist in SAGD wells that result in "geysering" or slugging within the producing well. The energy available from water and steam is enormous. The nuclear and power industry previously made these similar discoveries after a series of catastrophic failures of piping systems. Analytical and computer simulation tools from the nuclear industry will be used to show that extremely high pressure transients, many times over fracture initiation pressures, can be expected. This is the same mechanism that resulted in the catastrophic failure of MEG Energy’s Christina Lake main steam distribution line. In summary, there is every reason to believe that when hot steam was injected into a cooled (water) condensate filled well; very large pressure transients can be expected from phase changes within the piping that should result in a frac to surface.

The analysis of fluid transport in fractured reservoirs is of great concern in petroleum and environmental engineering. The objective of this work is to study mass transfer between the matrix and the fracture network in such complex formations. In this study, the impact of adsorption on mass transfer in a fractured medium with variable fracture spacing is investigated. Development of a mathematical model for mass transfer in dual porosity systems enhances predictions of the rate of mass transfer between matrix and fracture. In addition, it provides a tool for an appropriate design of advanced oil and gas recovery processes. Mass transfer is modeled based on the advective-dispersive transport with adsorption in an infinite acting dual porosity reservoir under radially divergent and continuous injection. The fracture spacing has been taken into account by including the variable rock matrix block size distribution in the developed model. By employing this model, the effects of the adsorption rate on the mass transport in a subsurface environment are analyzed. The impact of the rate of adsorption on the accumulation of the injected tracer (catalyst) in a reservoir is investigated. An understanding of the effect of adsorption on advective-dispersive mass transport with variable fracture intensity can be a key finding to develop and design advanced oil recovery processes.

The use of pressure data to understand reservoir flow characteristics has been evolving since Darcy's Law was published in 1856. Welltesting has evolved from straightline methods to sophisticated interpretation models which use Log-Log pressure and derivative diagnostic plots to recognize flow regimes. This allows analysis to be performed on a valid subset of the data. It has long been known that reservoir fluid flow alone will very rarely if ever create a Bourdet derivative slope of greater than one. Mohamed et al (2011) showed that for tight shale gas mini-fracs, the derivative slope during fracture closure is equal to 3/2. This diagnostic signature is readily apparent in Mini-Frac tests of the Alberta oilsands caprock which flags it as a nonreservoir geomechanical effect. Mattar (1997) showed reservoir flow has a characteristic shape on the primary pressure derivative plot: the primary pressure derivative data continuously declines for all reservoir flow regimes. The primary pressure derivative appears to stop declining while the fracture is closing and resumes declining after the fracture is closed (it can increase for the forced closure case). Barree et al (2009) uses G Function and Square Root plots and their derivatives to indentify flow regimes as the basis for establishing fracture closure. This sounds familiar to Bourdet's pressure derivative rationale. This paper shows these methods compliment conventional PTA and give consistent repeatable mini-frac solutions for oilsands caprocks. The incorporation of fracture solutions into PTA programs is another step forward to delivering reliable, consistent analysis for mini-fracs, however, these solutions only exist for falloff whereas the 3/2 slope and primary pressure derivative also work for flowback assisted fracture closure. Several examples will be presented to illustrate that Pressure Transient Analysis is a useful tool for resolving Mini-frac data, especially the start and end of fracture closure.