Summary The prediction of dynamic elastic constants of reservoir rocks is one of the most important aspects of petroleum engineering. In recent years, several studies have been performed for this purpose. Because of uncertainty and variability in natural materials, deterministic prediction of rock properties in the reservoir is not reasonable. The purpose of this study is to evaluate uncertainty in dynamic-elastic-constant prediction for reservoir rock. Dipole-shear-sonic-image (DSI) log data from one of the Saudi Arabian reservoirs are used to evaluate uncertainty in dynamic-elastic-property prediction. For this purpose, a multiple linear regression (MLR) is carried out to present an empirical equation for shear-wave (S-wave) velocity prediction. Then, probabilistic analysis using Monte Carlo simulation (MCS) is performed to evaluate the uncertainty and reliability in prediction of dynamic elastic constants (Young's modulus and Poisson's ratio). On the basis of the analysis, uncertainty and variability of rock elastic constants are considered, and the value of Young's modulus and Poisson's ratio in a special interval from the reservoir are determined with a certain probability. Finally, the impact of log-data parameters on the value of rock elastic constants in the reservoir interval is assessed.

Summary The presence of an oil-viscosity gradient appears to be a real phenomenon in the field, and its influence on the steam-assisted-gravity-drainage (SAGD) process has been studied by various researchers. However, there is potential to refine previous results to exploit the impact of viscosity gradients on SAGD-oil-recovery-process performance. This paper covers our simulation study of the impact of an oil-viscosity-gradient presence on SAGD operation. Various SAGD operating scenarios in the reservoir with the presence of a vertical oil-viscosity gradient were investigated and simulated. The conclusions are summarized as follows: The presence of a vertical oil-viscosity gradient in the reservoir had a mild effect on the SAGD-oil-recovery rate, while the effect on the oil-recovery factor was insignificant. J-Well SAGD, in which a J-well replaces the horizontal producer in a standard SAGD-well configuration, did not perform as well as SAGD with a standard well configuration (two parallel horizontal wells). These two conclusions are not in agreement with previous findings by other research groups. Observations from some SAGD field tests indicate that the steam chamber could fail to reach the top of reservoirs. For those cases, gas injection could potentially help to recover the oil from the layer above the steam chamber. If that is true, the presence of an oil-viscosity gradient might have some impact on SAGD performance with gas injection. Because local steam-trap control is required for J-Well SAGD (JAGASS) operation to optimize performance, the challenge and feasibility of local steam-trap control are also discussed in this paper. Some of the SAGD field evidence will be provided to support our simulation results.

Summary British Columbia (B.C.) has seen near-exponential growth in the areas of the Horn River and Montney unconventional shale-gas plays situated in northeastern B.C. (Fig. 1). The original-gas-in-place volume for the Montney and Horn River basins has not been formally calculated, but it has been estimated at greater than 500 Tcf and continues to be revised upwardly as new and more-refined information is obtained and development takes place. The Cordova embayment and Liard basin, east and west (respectively) of the Horn River basin, are at early stages of assessment but promise additional massive gas-in-place values. Approximately 5 years ago, industry experts were predicting a dramatic reduction in viable gas production from the western Canada sedimentary basin, and from North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG), in which gas from offshore suppliers could be imported and moved through the North American transportation grid to market. Regulators were anticipating an influx of LNG-facility applications and myriad infrastructure modifications to handle the resulting new flow regime. In 5 short years, this dire future has been reversed completely because of the advent of economically viable methods to access gas trapped in shales and similar tight formations. At the current rates of production and exploration, there are more than 20 years of gas reserves in B.C., reversing a previous decline, as shown in Fig. 2. B.C. is ideally positioned to provide gas to North America with ready access to a number of major gas-transportation pipelines, including systems operated by TransCanada Pipelines, Spectra Energy Gas Transmission, and the Alliance Pipeline. Many of these systems are undergoing significant capacity expansions to accommodate the influx of gas from these new plays. This paper will explore the challenges posed to regulators in rapidly moving from conventional vertical-well developments to unconventional multiwell pads consisting of multiple fracture-stimulated horizontal wells.

Summary A numerical fully implicit nonisothermal wellbore/reservoir simulator is developed. The model entails simultaneous solution of transient coupled mass-, momentum-, and energy-balance equations within the wellbore; energy-balance equations for the tubular and cement materials and the formation surrounding the wellbore; and mass-balance and flow-rate/pressure equations for the reservoir formation. A wellbore heat-loss model that is a strong feature of this study is developed and employed in the model to improve the accuracy of the simulator and to be able to estimate the casing temperature and formation-temperature distribution. The model formulation is completed with an equation of state (EOS) to estimate fluid properties and appropriate friction-factor correlations in the wellbore tubing to compute the frictional pressure drop for different flow regimes. The developed model has several applications in the petroleum industry, particularly in the gas-well testing design and interpretation of both isothermal and nonisothermal gas reservoirs. This nonisothermal simulator is validated through comparisons to both analytical models and an equivalent numerical isothermal coupled wellbore/reservoir simulator that is also developed in this paper. Applications of this simulator to analyzing gas-well testing problems, in addition to several important observations, are extensively studied in Part 2 of this research work (Bahonar et al. 2010). Currently, it has been well accepted that the applicability and significance of a reservoir simulator depend on the behaviour of the wellbore and interaction between the wellbore and reservoir. A robust, accurate coupled wellbore and reservoir simulator is an invaluable tool for the petroleum engineer to help the petroleum industry understand production behaviour, make a meaningful prediction, and make correct decisions in all field-development and production stages.

Summary Naturally fractured reservoirs (NFRs) represent more than 20% of the world's oil and gas reserves. However, their characterization is complex and presents unique challenges in comparison with conventional reservoirs. It is immensely difficult to achieve the best results in the secondary-recovery process for NFRs. This paper presents a successful development of waterflooding to overcome the complex geological characterization of the White Tiger field, the largest fractured basement reservoir to date on the continental shelf of Vietnam. This reservoir has a complicated geological structure, with high heterogeneity, high temperature, and high closure stress. The total oil initially in place (OIIP) of this field reached nearly 4 billion bbl from 2000 m of oil-bearing thickness, and the field has been produced by more than 100 wells, 10 of which have flowed at the rate of approximately 1,000 B/D. The geological study and fractured model have been carefully investigated in both micro- and macroscale to improve waterflooding performance. The authors have analyzed the advantages and disadvantages of injection systems in this basement reservoir during 20 years of production history, and an artificial water buffer solution has been proposed to improve the waterflooding process. The authors have described the establishment and association of local artificial water buffer in the basement reservoir. An effective method to optimize the injected-water volume has also been discussed. Promising results from the White Tiger field have shown that the average reservoir pressure and total oil recovery have increased significantly in comparison with previous injection schemes. This paper presents useful guidelines to solve some typical problems of waterflooding in fractured basement reservoirs: What can be applied in waterflooding for a fractured basement reservoir? What is the optimal injection rate and injected volume for the fractured basement reservoir? How do we evaluate the probability of high water cut in production wells during the waterflooding process? How do we predict the rise of an artificial water/oil contact (AWOC)?

Summary Modern production-decline analysis is a robust technique for analysis of production data from a well under variable operating conditions. It uses production rates and flowing pressures to provide reliable estimates of recoverable reserves and fluid in place. The mathematics behind this technique is similar to that of pressure-transient theory; however, the focus is different. It deals with long-term variable production data instead of short-term constant-rate transient data. Using modern decline analysis for two-phase-flow conditions (e.g., gas/condensate reservoirs) is under question because of the single-phase-flow assumption in the development of a "material-balance time" function. This is a time function that converts any decline (e.g., exponential decline) to harmonic decline to account for variable operating conditions. The purpose of this work is to develop a model to use the concepts of modern techniques for analyzing production data of single-porosity gas/condensate reservoirs. For this purpose, the governing flow equation is linearized, using appropriately defined pseudopressure and pseudotime functions. Then, the solution is obtained for constant-well-rate condition. This is followed by employing the superposition theorem to account for variable well pressure/rate conditions, resulting in definition of two-phase material-balance pseudotime. The solution developed here is coupled with an appropriate material-balance equation and used to estimate the average reservoir pressure and original gas in place from analyzing production data. The dependency of relative permeability on capillary number and non-Darcy flow is included in the formulation. Verification of the proposed method is obtained with the analysis of synthetic production data using a series of fine-grid compositional numerical simulations over a typical range of gas/condensate-reservoir parameters.

Summary Reservoir simulation and research activities of heavy oil production processes (steam-assisted gravity drainage, vapour extraction, or the steam/solvent combined hybrid process) require accurate values of equilibrium constants (K-values) at elevated temperatures. However, such data are rarely available in open literature either because of the temperature limitation of pressure/volume/temperature (PVT) equipment or difficulties in performing high-temperature three-phase vapour/liquid equilibrium (VLE) experiments. In this paper--with the assistance of a state-of-the-art fully visual PVT cell that was specifically developed for heavy viscous oils, is capable of performing fluid-phase-behaviour studies at temperatures up to 250°C, and that effectively mixes samples with viscosity up to 1,000 cp at test temperature--a heavy-oil/solvent/steam equilibrium case study is presented. The heavy oil was mixed with solvent and water at a specified weight ratio, temperature, and pressure in the heavy-oil PVT cell. After achieving equilibrium, the volumes of vapour, liquid, and water phases were measured. The samples from each phase were drawn for compositional analysis using gas chromatography (GC), and K-values of the hydrocarbon components were examined. The component compositions from this experiment were used for equation-of-state (EOS) model tuning. This case study shows that with proper care, the EOS can be characterized and used to match with experimental data for heavy oil.

Summary Steam-assisted gravity drainage (SAGD) has proved to be a commercially viable method to extract bitumen from oil-sands reservoirs in western Canada. To understand the influence of steam injection on reservoir and surrounding rocks and potential impacts of surface deformation on the environment, various types of instrumentation and 4D-seismic surveys have been applied in SAGD projects. The effect of geomechanics on SAGD has been well documented. Collecting essential geomechanical data, properly interpreting them, and incorporating them into numerical models are necessary to ensure meaningful history matching and understanding of reservoir performances. This paper outlines geomechanical-data acquisition and field-monitoring methods from a reservoir-engineering perspective, and the applications of geomechanics in SAGD analyses. Minimal-data-acquisition programs are suggested to collect the necessary geomechanical data for different analysis purposes in SAGD projects. Primary instrumentation is briefly overviewed, and recommendations for instrumentation selection are provided. Using generic Canadian-oil-sands reservoir and rock properties, the subsurface and surface changes and deformations are simulated, including permeability changes, reservoir movements, and strains and surface uplifts. Simulations are completed with a widely applied thermal simulator, and its limitations are also discussed. The method to couple the results of geostatistics modelling, reservoir simulation, and geomechanics in SAGD simulation and to link them with a 4D-seismic survey in history matching is provided.

Summary Steam-assisted gravity drainage (SAGD) is a commercially successful recovery process that produces heavy oils and bitumen. The method ensures both a stable displacement front of steam and economical rates by using gravity as the driving force with a pair of horizontal wells for injection/production. Although several ways of improving the performance have been discussed in the literature, the well configuration employed in the process has remained the same as originally proposed by Butler et al. (1981). A systematic attempt to improve the performance by using radically different well configurations has not been reported. This paper presents a study intended to examine the applicability of a new well configuration to SAGD processes in Athabasca and Cold Lake reservoirs in central and northern Alberta. The fully implicit thermal-reservoir simulator, CMG's STARS 2007, with fully coupled wellbores was used to account for frictional pressure drop and heat losses along the wellbore. 3D numerical simulation models were set up, and sensitivity analyses were conducted on injection pressure. After optimization of the injection pressure, an investigation of new well configurations was conducted using these models. The result of this work shows that the SAGD-process performance in Athabasca and Cold Lake reservoirs can be improved significantly by changing the well configuration.

Summary Three pump-intake-pressure (PIP) calculation methods available for wells artificially lifted with sucker rods are discussed in detail in this paper. The values of PIP obtained from acoustic fluid-level measurements in wells with moderate pump submergence can yield PIP estimates that agree with those of pump fluid-load analysis. If PIPs determined using these methods do not agree, then the operator must review the data quality and may reduce the deviation by adjusting certain parameters affecting the calculations. Field data for a significant group of wells are used to compare the PIP results of the three methods. The results show that the PIP computed using the maximum and minimum pump dynamometer loads usually calculates a PIP that is too low, while the PIPs computed using the valve test loads are usually too high. Recommendations are presented for quality control of the computed values.