Initial Reservoir Conditions Research Articles

Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives

Summary Fracturing-fluid loss into the formation can potentially damage hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field to dissipate the lost water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants have potential to reduce the effect of fracturing-fluid loss on hydrocarbon permeability in the matrix. Unconventional tight reservoirs can differ significantly from one another, which could make the use of these techniques effective in some cases but not in others. We present an experimental investigation dependent on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants for hydrocarbon permeability for different initial reservoir conditions (IRCs). From this work, we identify the mechanism responsible for the permeability reduction in the matrix, and we suggest criteria that can be used to optimize fracturing-fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.

Cracked Naphtha Coinjection in Steam-Assisted Gravity Drainage

Steam-assisted gravity drainage (SAGD) is a thermal in situ recovery method for heavy oil and oil sands that has been employed to exploit the vast petroleum deposits in the Athabasca region of northern Alberta that are not amenable to surface mining. Nevertheless, in spite of its success in recovering highly viscous bitumen, SAGD remains a costly technology that requires large energy input in the form of steam for each barrel of produced oil. This requires large quantities of water and natural gas, resulting in sizable greenhouse gas (GHG) emissions and extensive postproduction water treatment. There are ongoing efforts to make SAGD more energy-efficient and environmentally sustainable by reducing steam consumption while maintaining favorable oil production rates and ultimate oil recovery. Such efforts include the coinjection of steam and solvent in a process called expanding solvent SAGD (ES-SAGD) wherein bitumen that is essentially immobile at initial reservoir conditions is made mobile by heating and m...

Experimental Study of the Response Time of the Low-Salinity Enhanced Oil Recovery Effect during Secondary and Tertiary Low-Salinity Waterflooding

Despite it more than 500 papers being published on low-salinity (LS) water injection into sandstone oil reservoirs to enhance oil recovery, very few field applications of this enhanced oil recovery (EOR) technique are known. Laboratory investigations of LS water floods under tertiary conditions have shown varying results, and especially, the response time for establishing a new bank of oil in the porous medium has been too slow for application in the field. Usually, many pore volumes (PVs) of LS brine must be injected to obtain an increase in recovery of 5–10% of original oil in place (OOIP). Provided that the initial reservoir conditions for observing LS EOR effects are present, a close connection between the imposed pH gradient and additional oil recovery has been experimentally verified. To improve the chemical understanding of the LS EOR mechanism, it appeared important to study the development of the pH gradient because the HS brine is displaced by the LS brine. Therefore, the relationship between th...

Experiment on the Influence of Vertical Heterogeneity of Reservoir on the Steam Drive Effect

This paper carried out experimental studies on the influence of vertical heterogeneity of reservoir on the steam drive effect after multiple-round steam stimulations. Taking the actual productive process of a heavy oil reservoir as an example, a physical model for the vertical heterogeneity was established. First, under the initial reservoir conditions, conduct multiple rounds of steam stimulations to obtain the initial reservoir conditions of steam drive, and then carry out physical simulation of steam drive, including the simulation of the horizontal reservoir and the tilted one. The development of temperature field and the oil-water output changes indicate that when the steam drive is conducted after the steam stimulations, the steam advances along the high permeability layer with better steam stimulation effect, once it gets a breakthrough, the swept volume will not change. For the tilted reservoir, due to the beneficial effects of the gravity drainage, its displacement effect is better than the horizontal one, which provides an important basis for the adjustment of layers and the section of methods of gas injection when the steam simulation is converted into steam drive.

Stress arching effect on stress sensitivity of permeability and gas well production in Sulige gas field

Permeability is a fundamentally important parameter of hydrocarbon reservoir because it significantly impacts well productivity. In laboratories, it is measured under isotropic load which is equal to overburden pressure and it is often assumed to remain unchanged during production. In really however, stress arch forms above the reservoir and the overburden pressure drops during production. Consequently, there is a clear need to illustrate the stress arching effect on the stress sensitivity of permeability and well dynamic performance. Stress arching ratio, which is defined as the change in overburden pressure divided by the change of pore pressure from initial reservoir condition, is calculated for different reservoir shapes in Sulige gas field. Relationship between overburden pressure and effective stress considering stress arching effect in Sulige gas field has been established. Laboratory experiments following reservoir depletion path have been conducted under the stress arching ratio of 0.12 and 0.28 that the reservoir may follow. The results show that the stress sensitivity of permeability greatly depends on stress arching ratio. Permeability measured under nonzero stress arching ratio is larger than that obtained from the conventional experiments with the stress arching ratio of 0 under the same condition. At the pressure drop of 25 MPa, the measured permeabilities increase by 23% and 50% for the stress arching ratios of 0.12 and 0.28, respectively, compared with the values obtained by the conventional experiments when the initial permeability of the core is 0.098 md. In contrast, the permeability shows less dependence on stress arching ratio when the initial permeability of the core is large, such as 7.387 md. Furthermore, the effect of stress arching ratio is introduced into the calculation of well productivity based on the experiment results. The gas well productivities increase by 5.03%, 12.46% and 72.48% for stress arching ratios of 0.12, 0.28 and 1, respectively, when the reservoir initial permeability is 0.098 md. The impact of stress arching ratio on dynamic performance of gas well is generally incorporated via look-up tables of transmissibility multiplier in Eclipse, which is approximate to the ratio of the decreased permeability to the initial permeability for different stress arching ratio. The production decline rate and production decline type are closely related with stress arching ratio when the initial permeability is 0.098 md. This work investigates the stress arching effect on stress sensitivity of permeability for cores with different initial permeabilities. it can provide some insights into gas productivity calculation, production forecasting, and gas recovery determination

Prediction of Stimulated Reservoir Volume and Optimization of Fracturing in Tight Gas and Shale With a Fully Elasto-Plastic Coupled Geomechanical Model

Summary Hydraulic fracturing is essential for the economic development of tight gas reservoirs and shale-gas reservoirs. Current techniques are unable to predict the stimulated-reservoir-volume (SRV) dependence on fracturing-job and rock-mechanics parameters, which precludes any meaningful optimization. In the authors' previous work on the SRV-propagation prediction, the combined tensile/shear fracturing model applied to the fracturing of tight gas formations has shown the creation of a relatively narrow, focused SRV that resembled behavior dominated by a single fracture. In this work, the model has been significantly improved by the implementation of a rigorous full Newton elasto-plastic solution of the geomechanics of rock containing induced fractures. The results reveal interesting features of complex-fracture propagation in tight formations, which are in broad agreement with the shapes of SRVs obtained from microseismic imaging. The developed code is flexible enough to allow either tensile or shear fracturing or the occurrence of both to be examined on the basis of initial reservoir conditions. Different cases of 2D and 3D simulations will be presented that demonstrate some important features of the process. First, it is found that a wide SRV can result in cases in which initial reservoir conditions are close to the shear-fracturing point, such as in formations with microfractures, partially cemented natural fractures, and abnormally high initial pore pressure. Second, the SRV width is found to depend on the horizontal stress contrast, as expected. Third, wide SRV growth is associated with constant or increasing pumping pressure necessary for further failed-zone growth as a result of the loss of elastic coupling by off-planar failure propagation. Further, under high injection pressure, an efficient fracture elasto-plastic constitutive model developed can drive both maximal and minimal effective stresses to zero or tensile, and, therefore, the creation of tensile fracturing can be predicted simultaneously with shear fracturing. This will then provide a means of modeling proppant transport. The new model is a significant step toward the development of an integrated predictive tool for the optimization of shale-gas development.

Swelling Measurements of a Low Rank Coal in Supercritical CO<sub>2</sub>

Coal swelling in the presence of water as well as CO2 is a well-known phenomenon, and these may affect the permeability of coal. Quantifying swelling effects is becoming an important issue to verify the suitability of particular coal seams for CO2-enhanced coal bed methane recovery projects. In this report, coal swelling experiments using a visualization method in the CO2 supercritical conditions were conducted on crushed coal samples. The measurement apparatus was designed specifically for the present swelling experiment using a visualization method. Crushed coal samples were used instead of block coal samples to shorten equilibrium time and to solve the problem of limited availability of core coal samples. Dry and wet coal samples were used in the experiments because there is relatively limited information about how the swelling of coal by CO2 is affected by water saturation. Moreover, some coal seams are saturated with water in initial reservoir conditions. The maximum volumetric swelling was around 3% at 10 MPa for dry samples and almost half that at the same pressure for wet samples. The wet samples showed lower volumetric swelling than dry ones because the wet coal samples were already swollen by water. Experimental results obtained for swelling were comparable with other reports. Our visualization method using crushed samples has advantages in terms of sample preparation and experimental execution compared with the other methods used to measure coal swelling using block samples.

Long-Term Gas-Hydrate-Production Test, North Slope, Alaska

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22152, ’Evaluation of the Hydrate Deposit at the PBU-L106 Site, North Slope, Alaska, for a Long-Term Test of Gas Production,’ by George J. Moridis, SPE, and Matthew T. Reagan, SPE, Lawrence Berkeley National Laboratory; Heidi Anderson-Kuzma, SPE, East Donner Research; Yang Zhao, University of California at Berkeley; Katie Boyle, Lawrence Berkeley National Laboratory; and James W. Rector, University of California at Berkeley, prepared for the 2011 Arctic Technology Conference, Houston, 7-9 February. The paper has not been peer reviewed. To investigate the technical feasibility of gas production from hydrate deposits, a long-term field test (lasting 18 to 24 months) is under consideration in a project led by the US Department of Energy. A candidate deposit involving the C-Unit in the vicinity of the PBU-L106 site on the North Slope, Alaska, was evaluated. The results indicate that production from horizontal wells may be orders of magnitude larger than that from vertical wells. Introduction Gas hydrates (GHs) are solid crystalline compounds of water and gaseous sub-stances that are described by the general chemical formula GsNH H2O. In the GH clathrates, the molecules of gas, G (referred to as guests), occupy voids within the lattices of ice-like crystal structures. If gas and H2O availability is not a limitation, hydrate deposits can occur in two distinctly different geographic settings in which the necessary conditions of low temperature, T, and high pressure, P, exist for their formation and stability: in the Arctic (typically in association with permafrost) and in deep ocean sediments. CH4 is the dominant GH-forming hydrocarbon gas in natural hydrates that occur in geologic media. Under standard T and P (STP) conditions, each cubic meter of simple CH4 hydrate releases, upon dissociation, approximately 164 m3 of methane and 0.8 m3 of H2O. Classification. Natural GH accumulations are divided into three main classes on the basis of simple geologic features and initial reservoir conditions. Class-1 settings have two layers: a hydrate- bearing layer (HBL) and an underlying two-phase-fluid zone containing mobile gas and liquid water. A distinct feature of Class-1 settings is that the base of the GH-stability zone coincides with the bottom of the HBL. Class 1 is the most desirable target because it is the easiest to destabilize to release gas. In Class-2 settings, an HBL overlies a zone of mobile water. Class-3 accumulations have a single HBL with no underlying zone of mobile fluids.

Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low-Permeability-Sandstone Gas Reservoir in the North Sea

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124067, “The Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low-Permeability-Sandstone Gas Reservoir in the North Sea,” by G. Coghlan, SPE, and B. Holland, SPE, Venture Production, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4–7 October. The paper has not been peer reviewed. To obtain commercial flow rates from the Chiswick field, a low-permeability gas reservoir in the UK Southern Gas basin, field development would require horizontal wells with multiple propped hydraulic fractures. Only a few such completions have been attempted in sandstone reservoirs of the North Sea. The initial field-development plan entailed two horizontal wells with 2-km-long reservoir sections, stimulated with several massive propped fractures. Introduction Chiswick is in a water depth of 42 m, approximately 160 km northeast of Great Yarmouth. A field-development plan was approved in 2006. The first-phase wells were completed on a minimum-facilities platform, and first gas was produced in September 2007. The field underwent a prolonged appraisal period following its discovery in 1984, directly reflecting the challenges posed by the low-quality Carboniferous sandstones that contain the majority of the gas. Geology The structure shown in Fig. 1 is a broad, northwest/southeast-trending, faulted anticline that is dip and fault closed with an almost square periphery. While a gas/water contact has never been drilled, a fieldwide contact at 3450 m true vertical depth subsea (TVDSS) can be inferred with fair accuracy. The area of closure is approximately 0.37 km2. The crestal part is at a depth of approximately 3250-m TVDSS. Crossfaults subdivide the field into five compartments: Alpha, Beta, Gamma, Delta, and Epsilon. Initial reservoir conditions were 3.92 MPa and 115°C at 3450 m TVDSS. Porosity ranges from 3 to 14% and water saturation from 25 to 70%. Total gas initially in place for the Carboniferous reservoirs was estimated at 11.3×106 m2. Chiswick Development Wells Initial development was two wells with 2- to 2.5-km-long horizontal sections, completed with five or six massive propped hydraulic fractures of 400,000 to 500,000 lbm each, spaced approximately 500 m apart. The formation dip allows a horizontal well to penetrate a succession of channels and connect several layered reservoirs. Within each channel, a propped fracture stimulates deliverability by exposing a large volume of rock to the wellbore.

Key Factors for Depressurization-Induced Gas Production from Oceanic Methane Hydrates

Oceanic methane hydrate (MH) deposits have been found at high saturations within reservoir-quality sands in the Eastern Nankai Trough and the Gulf of Mexico. This study investigates the key factors for the success of depressurization-induced gas production from such oceanic MH deposits. A numerical simulator (MH21-HYDRES: MH21 Hydrate Reservoir Simulator) was used to study the performance of gas production from MH deposits. We calculated the hydrate dissociation behavior and gas/water production performance during depressurization for a hypothetical MH well. Simulation runs were conducted under various initial reservoir conditions of MH saturation, temperature, and absolute permeability. A productivity function (PF) was introduced as an indicator of gas productivity, which is a function of gas production rate, water production rate, and discount rate. The simulations showed that recovery factors over 36% and maximum gas production rates over 450 000 Sm3/d were expected for the most suitable conditions of a class 3 deposit (i.e., an isolated MH deposit that is not in contact with any hydrate-free zone of mobile fluids). However, gas productivity was affected by formation temperature and initial effective permeability. The values of PF increased with increasing formation temperature when the initial permeability of the deposit was higher than a threshold value (the threshold permeability); however, it decreased for the deposit below the threshold permeability. The threshold permeability was estimated to be between 1 and 10 mD in the class 3 deposit. These results suggest that key factors for the success of depressurization-induced gas production from oceanic MH are as follows: (1) The initial effective permeability of the MH deposit is higher than the threshold value, and (2) the temperature of the MH deposit is as high as possible.

Chemical changes in natural features and well discharges in response to production at Wairakei, New Zealand

Development of the Wairakei geothermal resource has resulted in changes to the chemistry of the discharged fluids. The output of hot chloride springs declined rapidly and eventually ceased 10 years after the commencement of drilling. Deep pressures were drawn down by well discharge resulting in an increase in size and pressure of the shallow steam zone. Natural heat flow in the Karapiti Thermal Area increased from 40 MWt in 1950 to 420 MWt in 1964. Reduced reservoir pressures have also caused cool and less-mineralised water to enter the Western Borefield production reservoir. This reduced the average chloride concentration in the well discharges from 1580 g/t in 1960 to 1230 g/t in 2001. By this time 34% of the well discharge was from cool inflowing water and this has decreased to 27% in 2004. Since the mid-1980s production at Wairakei has been increasingly supported by fluid extracted from the Te Mihi sector. “Dry” steam wells, with gas concentrations up to 3.2 wt%, were brought into service in 1989, and in the last decade production has been added from deep liquid wells. By October 2007 the total gas flow to the Wairakei and Poihipi Power Stations was 9500 kg/h. Temperatures (∼250 °C) and compositions of the deep Te Mihi wells are close to the inferred initial reservoir conditions. The commencement of injection in 1995 and an increase in shallow groundwater drainage have increased concentrations of calcium and CO 2 in total discharge. This has resulted for the first time in problems of calcite scaling in some wells although chemical evidence of injection returns is inconclusive.

Models, Assumptions, and Stakeholders: Planning for Water Supply Variability in the Colorado River Basin1

Abstract: Declining reservoir storage has raised the specter of the first water shortage on the Lower Colorado River since the completion of Glen Canyon and Hoover Dams. This focusing event spurred modeling efforts to frame alternatives for managing the reservoir system during prolonged droughts. This paper addresses the management challenges that arise when using modeling tools to manage water scarcity under variable hydroclimatology, shifting use patterns, and institutional complexity. Assumptions specified in modeling simulations are an integral feature of public processes. The policymaking and management implications of assumptions are examined by analyzing four interacting sources of physical and institutional uncertainty: inflow (runoff), depletion (water use), operating rules, and initial reservoir conditions. A review of planning documents and model reports generated during two recent processes to plan for surplus and shortage in the Colorado River demonstrates that modeling tools become useful to stakeholders by clarifying the impacts of modeling assumptions at several temporal and spatial scales. A high reservoir storage‐to‐runoff ratio elevates the importance of assumptions regarding initial reservoir conditions over the three‐year outlook used to assess the likelihood of reaching surplus and shortage triggers. An ensemble of initial condition predictions can provide more robust initial conditions estimates. This paper concludes that water managers require model outputs that encompass a full range of future potential outcomes, including best and worst cases. Further research into methods of representing and communicating about hydrologic and institutional uncertainty in model outputs will help water managers and other stakeholders to assess tradeoffs when planning for water supply variability.

Sensitivity of time‐lapse seismic to reservoir stress path

The change in reservoir pore pressure due to the production of hydrocarbons leads to anisotropic changes in the stress field acting on the reservoir. Reservoir stress path is defined as the ratio of the change in effective horizontal stress to the change in effective vertical stress from the initial reservoir conditions, and strongly influences the depletion-induced compaction behaviour of the reservoir. Seismic velocities in sandstones vary with stress due to the presence of stress-sensitive regions within the rock, such as grain boundaries, microcracks, fractures, etc. Since the response of any microcracks and grain boundaries to a change in stress depends on their orientation relative to the principal stress axes, elastic-wave velocities are sensitive to reservoir stress path. The vertical P- and S-wave velocities, the small-offset P- and SV-wave normal-moveout (NMO) velocities, and the P-wave amplitude-versus-offset (AVO) are sensitive to different combinations of vertical and horizontal stress. The relationships between these quantities and the change in stress can be calibrated using a repeat seismic, sonic log, checkshot or vertical seismic profile (VSP) at the location of a well at which the change in reservoir pressure has been measured. Alternatively, the variation of velocity with azimuth and distance from the borehole, obtained by dipole radial profiling, can be used. Having calibrated these relationships, the theory allows the reservoir stress path to be monitored using time-lapse seismic by combining changes in the vertical P-wave impedance, changes in the P-wave NMO and AVO behaviour, and changes in the S-wave impedance.

Sensitivity of time‐lapse seismic to reservoir stress path

ABSTRACTThe change in reservoir pore pressure due to the production of hydrocarbons leads to anisotropic changes in the stress field acting on the reservoir. Reservoir stress path is defined as the ratio of the change in effective horizontal stress to the change in effective vertical stress from the initial reservoir conditions, and strongly influences the depletion‐induced compaction behaviour of the reservoir. Seismic velocities in sandstones vary with stress due to the presence of stress‐sensitive regions within the rock, such as grain boundaries, microcracks, fractures, etc. Since the response of any microcracks and grain boundaries to a change in stress depends on their orientation relative to the principal stress axes, elastic‐wave velocities are sensitive to reservoir stress path. The vertical P‐ and S‐wave velocities, the small‐offset P‐ and SV‐wave normal‐moveout (NMO) velocities, and the P‐wave amplitude‐versus‐offset (AVO) are sensitive to different combinations of vertical and horizontal stress. The relationships between these quantities and the change in stress can be calibrated using a repeat seismic, sonic log, checkshot or vertical seismic profile (VSP) at the location of a well at which the change in reservoir pressure has been measured. Alternatively, the variation of velocity with azimuth and distance from the borehole, obtained by dipole radial profiling, can be used. Having calibrated these relationships, the theory allows the reservoir stress path to be monitored using time‐lapse seismic by combining changes in the vertical P‐wave impedance, changes in the P‐wave NMO and AVO behaviour, and changes in the S‐wave impedance.

Wave sequences for solid fuel adiabatic in-situ combustion in porous media

We study the Riemann problem with forward combustion due to injection of air into a porous medium containing solid fuel. We neglect air compressibility and heat loss to the rock formation. Given initial reservoir and injection conditions, we prove that there is a unique time asymptotic wave sequence for combustion with complete oxygen consumption. The sequence consists of a region of unburned air at injection temperature, a warming discontinuity, a hot region with unburned air, a combustion wave and a region with burned air and unburned fuel at the initial reservoir temperature. The waves have very different speeds, and therefore they cannot be detected in laboratory experiments that focus on the combustion wave. However, they should occur in field scale. By introducing a cut-off in Arrhenius' law, the reaction rate vanishes at reservoir temperature, and two types of wave sequences are possible. One was already described. The other occurs for incomplete oxygen consumption. In this case, the wave sequence contains another wave, i.e., there is another region ahead of the combustion wave containing incompletely burned air at reservoir temperature, and a gas composition discontinuity that moves fast. However, instead of a unique solution for each Riemann data, there is a one parameter family of wave speeds and strengths. This multiplicity of solutions may to be due to the cut-off.

A laboratory feasibility study of dilute surfactant injection for the Yibal field, Oman

The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current waterflooding. The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was based on IFT values at different concentrations. The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4% of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.

PIC, Dow plan ethylene complex in Kuwait

The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current waterflooding.The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was based on IFT values at different concentrations.The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4% of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.

Effective processing of nonrepeatable 4-D seismic data to monitor heavy oil SAGD steam flood at East Senlac, Saskatchewan, Canada

The concept of time-lapse (or 4-D) seismic monitoring is straightforward: A baseline 3-D survey describing initial reservoir conditions and a subsequent monitor survey (or surveys) recorded after conditions have changed are calibrated, compared, and the intersurvey differences analyzed and interpreted in terms of net variations in pore fluid saturation, pressure, or temperature inside a hydrocarbon reservoir.

The Effect of Geological and Geomechanical Parameters on Reservoir Stress Path and Its Importance in Studying Permeability Anisotropy

Summary Reservoir stress path is defined as the ratio of change in effective horizontal stress to the change in effective vertical stress from initial reservoir conditions during pore-pressure drawdown. Measured stress paths of carbonate and sandstone reservoirs are always less than the total stress boundary condition (isotropic loading) and are either greater or less than the stress path predicted by the uniaxial strain boundary condition. Clearly, these two boundary-condition models that are commonly used by the petroleum industry to calculate changes in effective stresses in a reservoir and to measure reservoir properties in the laboratory are inaccurate and can be misleading if applied to reservoir management problems. A geomechanical model that incorporates geologic and geomechanical parameters was developed to more accurately predict the reservoir stress path. Numerical results show that reservoir stress path is dependent on the size and geometry of the reservoir and on elastic properties of the reservoir rock and bounding formations. In general, stress paths become lower as the aspect ratio of reservoir length to thickness increases. Lenticular sandstone reservoirs have a higher stress path than blanket sandstone reservoirs that are continuous across a basin. This effect is enhanced when the bounding formations have a lower elastic modulus than the reservoir and when the reservoir is transversely isotropic. In addition, laboratory experiments simulating reservoir depletion for different stress path conditions demonstrate that stress-induced permeability anisotropy evolves during pore-pressure drawdown. The maximum permeability direction is parallel to the maximum principal stress and the magnitude of permeability anisotropy increases at lower stress paths.

The Steam and Gas Push (SAGP)-2:Mechanism Analysis and Physical Model Testing

Abstract At the 48th Annual Technical Meeting of the Petroleum Society, one of us presented a paper that showed that there was a possibility of making the SAGD process more efficient by adding a small concentration of a non-condensible gas such as methane to steam(1). For this to be effective the steam injection well should be located slightly above the production well. With this configuration, and with a small continuous production of gas with the produced oil and condensate, the non-condensible gas becomes concentrated in the upper part of the chamber and the heat loss to the overburden, and for the heating of the chamber, is greatly reduced; the steam oil ratio is much lower. Another configuration involves the continuous injection of a small stream of non-condensible gas from a well or wells near the top of the chamber with steam injection from a lower well or even into the production well. The heat is confined to the near wellbore region and again there is a considerable economy. The present paper discusses further analysis of these configurations and also results from physical model tests that are being carried out at the University of Calgary. The results of these experiments have been very positive and it appears that the concept may be even more effective than was predicted originally. The reason for this appears to be that the introduction of gas with steam invokes a new mechanism as the gas flows counter currently to the falling liquids; this mechanism involves the creation of a large surface area for mass transfer. As a result, the steam chamber is not only much lower in temperature, particularly at the top, but it also rises more slowly and spreads laterally more quickly. A larger volume is draining at a much lower temperature. Measurements made in our model show large improvements in the steam/oil ratio. The observation of the new mechanism suggests that this approach may have economic applications in fields having top water such as Surmont as well as in more normal type reservoirs. In general, the improved performance should broaden the range of reservoirs that can be produced economically. Introduction It is estimated that there are 273 billion m3 heavy oil and bitumen in place in Canada. They are deposited mainly in the Athabasca, Cold Lake, Lloydminster, and Peace River areas. Conventional heavy oil (10 to 20 ° API), which is partially recoverable by conventional in situ methods, is less than 2﹪ of the total resources. Most of the bitumen has a viscosity ranging from 100,000 to over 1.0 million mPa ⋅s at reservoir temperature. It is present in a solid or semi-solid state in the porous media and there is almost no mobility at the initial reservoir conditions. The effective recovery of bitumen by in situ methods is difficult. The current production of bitumen is over 400,000 barrels a day, which constitutes about 70﹪ of the total heavy oil and bitumen production(2) in Canada.