Reservoir Engineering Analysis Research Articles

Feasibility Theory and Practice of CO2-EOR in High CO2-Content Near-saturated Edge-bottom Water Reservoir

Abstract CO2-EOR technology for low-permeability tight oil and gas reservoir is in the ascendant, and CO2-EOR technology for old oilfields has not been paid enough attention, but the implementation scale has great potential, and the expected effect and implementation conditions are good. The feasibility of CO2-EOR technology in the ultra-high water cut stage of high CO2 content, near saturation pressure and edge-bottom water reservoir was studied theoretically, and the field implementation effect was tracked and evaluated. Via petrophysics, reservoir engineering, and site case analysis, a relatively comprehensive reservoir numerical model was developed, clarifying the impact of periodic gas injection volume, gas injection rate, soak time and liquid production rate on the production effect of CO2 huff and puff were clarified. The key injection-production parameters of CO2 huff and puff test wells were designed, and the feasibility study progress of CO2-EOR in near-saturated edge-bottom water reservoirs with high CO2 content was summarized. The theoretical research shows that the change rules of gas-water dual-drive, CO2 water control and oil increase in the process of CO2 huff and puff in high CO2 near-saturated edge and bottom water reservoirs, and reveals the synergistic mechanism of CO2 huff and puff to suppress water and increase energy. The tracking evaluation shows that the sweep condition of CO2 after huff and puff in the test well is complex, the storage ratio is in the range of 40%-70%, the stage oil increase is in the range of 700t-3000t, and the optimized oil increase and oil change rate can reach 2.7t/t. Based on the comprehensive theory and practice, it is considered that CO2-EOR has good potential for high CO2 near-saturated edge and bottom water reservoirs under fine control. This study has guiding and reference significance for CO2-EOR technology and application in similar oilfields at home and abroad.

A new approach based on VIKOR and Monte-Carlo algorithms for determining the most efficient enhanced oil recovery methods: EOR screening

Most of oil reservoirs in the world have faced decrease in production and they are in the second half of their life cycle. Therefore, tertiary and enhanced oil recovery (EOR) techniques are needed for continuous production from these reservoirs. As choosing the most appropriate EOR methods for a reservoir is a challenging task for reservoir engineers, screening of EOR approaches is of high importance before any full field simulation and experiments. Enhanced oil recovery screening is a multiple criteria decision-making (MCDM) problem and hence, a systematic statistical algorithm based on MCDM can be used for this purpose. In this study, for the first time, a new EOR screening method is proposed by using VIKOR and Monte-Carlo algorithms. The approach used a large database of successful EOR projects around the world and was applied to 12 various EOR methods including a wide range of conditions and properties. Pre-processing was performed on the gathered database and then based on reservoir engineering analyses and using a pairwise comparison matrix, initial weights were considered for the parameters in each EOR method. Afterward, these weights were used in the proposed VIKOR MCDM calculation algorithm and the corresponding numerical values of EOR techniques for each reservoir were obtained. Finally, the EOR method with the highest corresponding value was selected as the most suitable method. Results demonstrated that by using the presented approach, a high classification accuracy of 98% was obtained for different cases, which shows the proficiency and robustness of the developed screening algorithm. In addition, the reliability of the developed method was validated using data obtained from 11 oil reservoirs in the southwest of Iran. Also, the results were compared with the results of previous studies and they were in a very good match. The developed approach is less expensive and faster than full field simulation method and can be used as an efficient EOR screening approach for reservoirs with different properties in the world.

Well and reservoir characterization using combined temperature and pressure transient analysis: A case study

Significant temperature variations are measured in oil and gas production wells with large pressure drawdown such as high production rate wells and tight formations. The considerable heating or cooling effects in the wellbore sandface invalidates the assumption of isothermal fluid flow in porous media. While this assumption satisfies most of the classic reservoir engineering analyses, the potential of slight thermal effects are attracting extensive interest and numerous thermal models have been proposed recently.The pitfalls and weaknesses of pressure transient analysis have been extensively investigated since 1930's which is still persistence despite developments of more accurate analytical and numerical models. Some of the weaknesses are rooted in the assumption of isothermal fluid flow in well test analysis methods.In this paper, we show the power and added value of combining temperature transient analysis to complement pressure transient analysis. Interestingly, the characteristics of skin effect such as radius and permeability of the damaged zone can be determined from temperature measurements. We study various parameters such as rock and fluid heat capacity, rock thermal conductivity, rock porosity, rock permeability and skin properties to illustrate the effect of each parameter on wellbore temperature data and hence the application of TTA for reservoir characterization. Using an accurate thermal flow mode, a case study has been done to investigate the importance of temperature transient analysis to better characterize an oil field well.

Machine Learning to Rate and Predict the Efficiency of Waterflooding for Oil Production

Waterflooding is a widely used secondary oil recovery technique. The oil and gas industry uses a complex reservoir numerical simulation and reservoir engineering analysis to forecast production curves from waterflooding projects. The application of such standard methods at the stage of assessing the potential of a huge number of projects could be computationally inefficient and requires a lot of effort. This paper demonstrates the applicability of machine learning to rate the outcome of waterflooding applied to an oil reservoir. We also explore the relationship of project evaluations by operators at the final stages with several performance metrics for forecasting. Real data about several thousand waterflooding projects in Texas are used in the current study. We compare the ML models rankings of the waterflooding efficiency and the expert rankings. Linear regression models along with neural networks and gradient boosting on decision threes are considered. We show that machine learning models allow reducing computational complexity and can be useful for rating the reservoirs, with respect to the effectiveness of waterflooding.

Drainage mechanisms in gas reservoirs with bimodal pores – A core and pore scale study

Underground gas injection and storage is principally used to meet variations in demand and supply of natural gas and for geosequestration. Reservoir engineering analysis of underground gas flow requires accurate modelling of the reservoir pores and their displacement mechanism. Modelling of multimodal pores like carbonates is quite challenging because of the difficulty in defining how two or more pore types interface. Parallel or serial communication between reservoir pores are the commonly used configurations in reservoir models. However, the factors controlling the communication pattern are not well understood and are rarely documented in the literature. Hence, the determination of the drainage pattern and the contribution from each pore type in a multimodal pore rock in the total flow process is done with some level of uncertainty. Capillary pressure (Pc) and electrical resistivity index (RI) curves can only indicate serial pore arrangement, but the combination of both also exists in some rocks. In this study, we employed a combination of nuclear magnetic resonance (NMR) relaxation measurements with Pc and RI methods to investigate how two pore types communicate during gas injection and the factors controlling their drainage pattern. Nitrogen was used as the gas phase to displace brine from different rock types covering limestones, dolostones, and sandstones. In another set of experiments, surfactant was added to the brine to ensure drainage of the micropores. We then developed an analytical workflow used to probe the drainage pattern and the contribution of the pore types. We quantitatively delineated the contributions of the macropores and micropores in the Pc and RI measurements and the intercommunication between them for the entire drainage process. The results showed that for a bimodal rock system, macropores and micropores are drained either in series, in parallel, or both depending on the rock structure. We found that the pore communication and drainage pattern correlate with the ratio of the macro and micro pores, the rock permeability, and log mean of the T2 relaxation of the rock. We also found that the drainage pattern controls the irreducible water saturation attained in each rock type.

Water Flooding Timing Research and Field Practice in Light Oil Reservoir

Water flooding timing is the research focus in the process of reservoir development, especially for offshore reservoir, reasonable water flooding timing can ensure better development effect, at the same time, it can save the investment cost in the process of reservoir development, so as to achieve sustainable and efficient development of offshore oilfield. At present, there are many researches on the flooding timing of conventional heavy oil reservoir, but few on the flooding timing of light oil reservoir. In order to clarify the development effect of light oil reservoir under different water flooding timing, taking offshore oilfield A as an example, combining with numerical simulation technology and reservoir engineering analysis method, the development effect under different water flooding timing is analyzed. The results show that when the reservoir pressure drops to half of the saturation pressure, the development effect of water flooding for light oil reservoir is the best. Therefore, the water flooding time can be postponed for the light oil reservoir with high porosity and permeability. The research results are applied to the actual development case of oilfield A. The practice shows that water flooding in the late development stage of light oil reservoir can effectively prolong the water-free oil production period, improve the initial oil recovery rate, reduce the initial development investment, thus effectively shorten the investment recovery period and improve the development effect of the reservoir in the whole life production cycle.

Reservoir architecture and evolution of meandering belt: A subsurface case in the Jiyang Depression, eastern China

The reservoir architecture of a meandering river deposition can indicate the heterogeneity of the subsurface reservoirs and deposition and evolution of the paleo-river. Although outcrop study has been useful in characterizing reservoir architecture, the study of the subsurface reservoir is still a challenge due to its complicated reservoir geometry and forming process. In this work, a mature oil field in Bohai Bay Basin, eastern China was investigated to understand the reservoir architecture and evolution of a Neogene meandering belt using drilling cores, well logging, 3D seismic data, and oil production data. In the study area, five types of litho-facies were observed indicating the specific hydrodynamic conditions. The results obtained two types of point bar combination models focused on (1) the point bars migration in the same direction at equal elevation and (2) erosion and superimposition of the multi-phase point bars. Abandoned channels in study area are classified into two types: Type Ⅰ is the “Early and long-term abandoned channel” and Type Ⅱ is the “Late and short-term abandoned channel”. Well log facies of Type Ⅰ presents a low sandstone/mudstone ratio while that of Type Ⅱ has a high sandstone/mudstone ratio. Both models exhibited the weakening of the seismic reflection amplitude and changes in the waveform. Based on the well log curves, stratal slicing, and seismic facies analysis, single point bars are interpreted more accurately. The meandering river in the study area, which was previously interpreted as a large single point bar, was comprehended as a meandering belt formed by a multi-phase point bar complex with three single point bars in the meander. Erosion and overlapping can be observed between the first and second phases of the point bars. In modern river deposition, similar meander reservoir architecture and its evolution can be observed. Additionally, reservoir engineering analysis showed that there are flow barriers between point bars of different phases. The reservoir architecture of a meandering belt was characterized and the depositional evolution of the paleo-river was reconstructed. The methods proposed is significant for qualitative interpretations of reservoirs such as morphology channel recognition, reservoir connectivity analysis, and lithology and interlayer prediction.

In-situ combustion front monitoring and tracking using InSAR

Interferometric synthetic aperture radar (InSAR) is used to locate the combustion front during field application of the in-situ combustion (ISC) enhanced oil recovery process. As the combustion front propagates through the reservoir during ISC, lateral surface deformation occurs on the order of 1–100 mm/year, depending on the reservoir depth and overlying strata, with a unique time derivative signature. Monitoring using InSAR benefits from the existence of a thin (tens of centimeters) high-temperature (600°C) combustion front to accurately determine the front position. This can inform reservoir and production engineering design decisions. Analytical and numerical examples of a homogeneous, isotropic, and horizontal reservoir show that regardless of the depth of the reservoir, the combustion front is positioned at the local maximum of the rate of surface deformation. These results are consistent with analytical solutions for distribution of point stress in the earth. This result is applied to the field case of Suplacu de Barcau, Romania, that has a long history of ISC. For the Suplacu Field, surface deformation rate data were generated using InSAR for the time periods of 12 March 2003 to 28 July 2010 and 29 October 2014 to 19 June 2017. The time derivative of surface deformation (surface velocity) suggests the advancement of the combustion front, consistent with reservoir engineering analyses in the literature. Importantly, the predicted positions of the combustion front match the available historical data for Suplacu in 2006 and 2010. We have also predicted the position of the combustion front in 2017 using the most recent InSAR data.

Insights From Interval Pressure Transient Tests Derive Key Fracture Parameters

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195435, “Macro Insights From Interval Pressure Transient Tests: Deriving Key Near-Wellbore Fracture Parameters in a Light-Oil Reservoir Offshore Norway,” by Alfredo Freites, SPE, Patrick Corbett, SPE, and Sebastian Geiger, SPE, Heriot-Watt University, et al., prepared for presentation at SPE Europec featured at the 81st EAGE Conference and Exhibition held in London, 3–6 June 2019. The complete paper describes the shortcomings of traditional well testing methods and the methodology and results of applying wireline-conveyed IPTT in a light-oil reservoir offshore Norway. The study focuses on cases in which fractures are present in the near-wellbore region but do not intersect the wellbore. The study included parameters such as fracture densities and conductivities, distance between fractures and wellbore, and the vertical extension of the fractures across geological beds. Introduction Fractures can be first-order controls on fluid flow in hydrocarbon reservoirs. Understanding fracture characteristics such as aperture, density, distribution, conductivity, and connectivity is key for reservoir engineering and production analysis. Well testing plays a key role in fracture characterization, particularly in fractured reservoirs. New advances in pressure transient analysis (PTA) have enabled the interpretation of production data such that the resulting geological scenarios are in better agreement with fracture patterns observed in out-crop analogs. Traditionally, drillstem-test (DST) data have been the primary source of information for well testing. However, the authors hypothesized that wireline-conveyed tools designed for interval pressure transient testing (IPTT) could yield a more-thorough description of near-wellbore heterogeneities, including fractures. To prove their hypothesis, they used a next-generation wireline testing tool to investigate the applicability of IPTT for characterizing fractured reservoirs, using detailed numerical simulations models with ac-curate wellbore representation to generate synthetic IPTT responses. The effect of the different fracture scenarios on the pressure transient tests was recorded as characteristic signatures on diagnostic plots, which the authors call IPTT-geotypes because they can be used to assist the interpretation of IPTT responses. The paper includes a field example of an IPTT case that was analyzed using the concept of geological well testing. Information from petrophysical logs and the IPTT-geotypes was integrated to assist the calibration of a reservoir model developed to represent the geological setting of the tested reservoir interval. The results provided a sound interpretation of the reservoir geology and quantitative estimation of the matrix and fracture parameters. IPTT Methodology Static characterization of fracture systems, which can be key controls on reservoir performance, rely on analog outcrop observations, seismic, image logs, and core analysis. Direct observations in cores; image logs; a sudden increase in mud filtration during drilling; and, at later stages, substantial differences between the wells’ expected and real productivity indices are all indicators of the presence of fractures in a reservoir. Well testing provides the means for dynamic characterization and is an area that has shown significant progress in recent years. The industry standard model for well test interpretation in naturally fractured reservoirs (NFRs) was developed in 1963. This model assumes a geometrically idealized system where flow occurs only in the fractures, which have uniform properties, while the matrix is stagnant and only recharges the fractures. Such a system normally does not represent real fracture networks. Features such as fracture geometry, density, and connectivity cannot be derived from the purely mathematical description.

Thermal characteristics of the X geothermal resources, and a recommendation on utilization possibility

Like in petroleum, geothermal has a high cost and risk in exploration, development including drilling and utilization. This needs a clear definition and understanding of the nature and characteristic of the system in question, so the increasing of investment cost and risk could be mitigated. Un-like in the petroleum industry, reservoir engineering and geoscience are intricately intertwined in geothermal. Considering this issue, in this study the author has integrated the results of reservoir engineering analysis with geoscience concept, to determine the up-flow zone, is a zone with high thermal potential and high permeability, so it can develop as geothermal field. It was conducted at a geothermal prospect in Indonesia located at the average altitudes of about 1000 meter above sea level (m.a.s.l), where 26 wells have been drilled. The research focus in characterising of the system, using wellbore temperatures and pressures measured. This will conclude the reservoir temperature and pressure as well as enthalpy, and up-flow zone by deploying several methods and approach: namely Horner temperature, BPD curve and Pivot concept, and thermal conductivity or heat transfer concept which applied in geoscience. The research includes a literature review on heat energy conversion to electricity based on reservoir temperature and or enthalpy approach, which is used to recommend the conversion system that can extract the heat efficiently. In addition, the question on location of the up-flow zone has been answered by this study, i.e. in the southern part of the field.

Subsurface engineering of CCUS in Australia (case studies)

Carbon capture utilisation and storage (CCUS) is a rapidly emerging field in the Australian oil and gas industry to address carbon emissions while securing reliable energy. Although there are similarities with many aspects of the oil and gas industry, subsurface CO2 storage has some unique geology and geophysics, and reservoir engineering considerations, for which we have developed specific workflows. This paper explores the challenges and risks that a reservoir engineer might face during a field-scale CO2 injection project, and how to address them. We first explain some of the main concepts of reservoir engineering in CCUS and their synergy with oil and gas projects, followed by the required inputs for subsurface studies. We will subsequently discuss the importance of uncertainty analysis and how to de-risk a CCUS project from the subsurface point of view. Finally, two different case studies will be presented, showing how the CCUS industry should use reservoir engineering analysis, dynamic modelling and uncertainty analysis results, based on our experience in the Otway Basin. The first case study provides a summary of CO2CRC storage research injection results and how we used the dynamic models to history match the results and understand CO2 plume behaviour in the reservoir. The second case study shows how we used uncertainty analysis to improve confidence on the CO2 plume behaviour and to address regulatory requirements. An innovative workflow was developed for this purpose in CO2CRC to understand the influence of each uncertainty parameter on the objective functions and generate probabilistic results.

Research on stress-sensitivity of fractured porous media

Stress sensitivity parameters of a fracture are often tested under compression on both sides of the fractured medium, which is considered as an elastic solid. However, the elastic solid assumption will fail when two fracture surfaces, if applied to tensile stresses, are out of contact. In such cases, effective stress in the fracture is zero and the change of fracture aperture is not determined by the fracture itself, but by the deformation of the matrix and the overall deformation of the fractured region. This paper proposed a zero-stress model that is applicable after the failure of elastic fracture model as described above. The model analyzes the deformation mechanism of fractures and derives a new equation that can be used to describe the aperture and permeability behavior of a fractured medium under the condition of zero stress. The model is derived for different geometric shapes of fractured region under hydrostatic pressures. The model equations can be used to calculate aperture and permeability changes caused by the production of oil and gas from a reservoir as well as the injection of water or gases for EOR. Sensitivity analysis of the model found that both shape factor of the fractured region and elastic modulus of the surrounding rocks have a significant impact on the outcome of the aperture and permeability forecast as a function of changing pore pressure. The permeability model can also be used in reservoir engineering analysis and reservoir numerical simulation. The new model is joined with the traditional elastic model to better describe the deformation process of fractures.

A New Way to Calculate Flow Pressure for Low Permeability Oil Well with Partially Penetrating Fracture

In order to improve the validity of the previous models on calculating flow pressure for oil well with partially perforating fracture, a new physical model that obeys the actual heterogeneous reservoir characteristics was built. Different conditions, including reservoir with impermeable top and bottom borders or the reservoir top which has constant pressure, were considered. Through dimensionless transformation, Laplace transformation, Fourier cosine transformation, separation of variables, and other mathematical methods, the analytical solution of Laplace domain was obtained. By using Stephenson numerical methods, the numerical solution pressure in a real domain was obtained. The results of this method agree with the numerical simulations, suggesting that this new method is reliable. The following sensitivity analysis showed that the pressure dynamic linear flow curve can be divided into four flow streams of early linear flow, midradial flow, advanced spherical flow, and border controlling flow. Fracture length controls the early linear flow. Permeability anisotropy significantly affects the midradial flow. The degree of penetration and fracture orientation dominantly affect the late spherical flow. The boundary conditions and reservoir boundary width mainly affect the border controlling flow. The method can be used to determine the optimal degree of opening shot, vertical permeability, and other useful parameters, providing theoretical guidance for reservoir engineering analysis.

Dynamic and static comprehensive prediction method of natural fractures in fractured oil reservoirs: A case study of Triassic Chang 6 3 reservoirs in Huaqing Oilfield, Ordos Basin, NW China

Abstract In consideration of the limited adaptability scope, low accuracy and high demand of great cost data of existent fracture prediction methods, a new fracture predicting method was advanced by implementing geological static data and production dynamic data from the Triassic Chang 63 reservoirs in the Huaqing Oilfield. Five constraints, lithology, sedimentary facies, thickness, rock rupture index and fracture intensity controlling the development of fractures were sorted out based on the static geological data. The multiple linear regression method was adopted to work out the quantitative relationships between the five constraints and fracture density, and the fracture density property of the whole area was calculated. Based on production dynamic data of well history, tracer, well interference test and intake profile test, the direction and distribution of fracture horizontally and vertically were figured out by reservoir engineering analysis method. The fracture density property was verified and quantitatively corrected with numerical simulation, and a 3D discrete fracture geological model in agreement with both geological cognition and dynamic production performance was built. The numerical simulation shows that the fracture model has higher fitting consistency, high reliability and adaptability.

Combination of Geological, Geophysical and Reservoir Engineering Analyses in Field Development: A Case Study

Combination of Geological, Geophysical and Reservoir Engineering Analyses in Field Development: A Case Study

New PVT Correlations Based on Libyan Crudes for Predicting Fluid Physical Properties

PVT properties are very important in reservoir and production engineering analyses such as material balance calculations, well testing, reserve estimation, inflow performance, production operations and design of surface facilities. New empirical PVT correlations have been developed for Libyan crudes with reliable degree of accuracy. These include; bubble point pressure (Pb), oil formation volume factor (Bo), gas solubility (Rs), stock tank oil molecular weight (Mwt), dead oil viscosity (μod), saturated oil viscosity (μob), under-saturated oil viscosity (μo), and oil compressibility (Co). Around 300 PVT samples collected exclusively from Libya, mainly Sirte, Ghadames and Murzuq basins, were used in our study to develop the above PVT correlations and covered wide range of API gravity (26 to 51°API) and reservoir temperature (100 to 313°F) normally found in Libyan reservoirs. Minitab regression tool was extensively used in our study to develop the PVT correlations and to statistically appraise them against the industry published correlations. The new proposed PVT correlations have demonstrated much better performance compared to the industry published correlations when tested for Libyan crudes. Also, Artificial Neural Network (ANN) models have been developed for Libyan PVT properties predictions. The models show acceptable accuracy and generally are more accurate than the empirical correlations.

Reservoir Dynamic Study in BZ 13-1 Oilfield

There are many uncertainty understanding on BZ13-1 oilfield, because of large area and less drilling wells and times. It belongs to critical reservoir between volatile reservoir and gas condensate reservoir. The dynamic law of BZ13-1 was obtained by the combine of dynamic history matching and reservoir engineering analysis method, situation analysis, reservoir connectivity analysis and gas-oil ratio variation studies. Also, different kinds of developing methods and influence factors were simulated and corresponding optimization suggestions to the development of the field were made.

Simulation of Flow-Control Devices With Feedback Control for Thermal Operations

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163594, ’Advanced Wellbore Simulation of Flow-Control Devices With Feedback Control for Thermal Operations,’ by Terry Stone, SPE, Schlumberger Information Solutions; Carlos Emilio Perez Damas, Schlumberger Calgary Regional Technology Centre; Glenn Woiceshyn, SPE, Absolute Completion Technologies; David Hin-Sum Law, SPE, Schlumberger Calgary Regional Technology Centre; George Brown, Schlumberger Fibre Optics Technology; and Peter Olapade and William J. Bailey, SPE, Schlumberger-Doll Research, prepared for the 2013 SPE Reservoir Simulation Symposium, The Woodlands, Texas, USA, 18-20 February. The paper has not been peer reviewed. Factors such as hydraulic gradients in the horizontal completion, geologic and fluid variations in the reservoir, and well-placement issues can produce very poor steam conformance in steam-assisted gravity drainage (SAGD). Using proportional-integral- derivative (PID) feedback to control steam injection can lead to improvements in SAGD. Inflow- or injection-control devices (ICDs) can also improve SAGD performance. This paper examines detailed wellbore simulations of a SAGD process in which wells are equipped with a combination of ICD completions and feedback control to determine the physical mechanisms and outline practical procedures to determine an improved ICD completion and feedback-control design. Introduction SAGD is the most extensively used process for development of the bitumen resources in western Canada. Fig. 1 shows the concept of this process in which two closely spaced horizontal wells are placed such that the upper well injects steam and the lower producer collects reservoir fluids that drain mostly by gravity from a constantly evolving steam chamber. Ideally, the steam chamber evolves uniformly along the entire length of the well pair. However, the actual pattern of SAGD well pairs shows very irregular steam-chamber development along the lengths of most of the pairs in the pattern. For many years, SAGD operators in this region have been evaluating methods to improve conformance along well pairs. One such method is to install dual- tubing strings in the injector and producer. Prescribed injection and production rates from each tubing string may be determined from a reservoir-engineering analysis of the formation around the pair, but such analyses are often inexact. In order to prevent the steam chamber from touching the lower producer, which would then remove hot steam instead of using it more efficiently in the upper reaches of the chamber, the injection and production rates are usually set to maintain a prescribed temperature difference between fluids exiting the upper injector and entering the lower producer. This temperature difference, also referred to as a “subcool” because it is set to be several degrees below a water saturation temperature, may be controlled at both the heel and the toe of the well pair by use of the ability to inject and produce from the two tubing strings that are landed at these points. However, setting these injection and production rates to reflect the current state of the reservoir and current subcool is difficult with conventional reservoir-engineering analysis. To improve on this, a proposal was made to use a feedback controller to monitor temperatures of produced and injected fluids automatically, with a target subcool at the heel and the toe of the well pair. By targeting the same subcool at the heel and the toe, two objectives are accomplished: (1) achieving the subcool prevents steam from entering the lower producer, and (2) both toe and heel halves are encouraged to produce uniformly because both are targeting the same subcool (i.e., if one-half temporarily operates at a lower or higher subcool than the target, steam injection is decreased or increased, respectively, in that half to compensate). Another method to improve conformance is to install carefully constructed ICDs in either the injector or the producer, or in both. When placed in the injector, these devices can equalize the outflow of steam from heel to toe better, regardless of variations in reservoir mobility properties.

Selecting Oil Wells for Hydraulic Fracturing: A Comparison between Genetic-Fuzzy and Neuro Fuzzy Systems

Hydraulic fracturing is widely used to increase oil well production and to reduce formation damage. Reservoir studies and engineering analyses are carried out to select the wells for this kind of operation. As the reservoir parameters have some diffuse characteristics, Fuzzy Inference Systems (FIS) have been tested for these selection processes in the last few years. This paper compares the performance of a neuro fuzzy system and a genetic fuzzy system used for selecting wells for hydraulic fracturing, with knowledge acquired from an operational data base to set the SIF membership functions. The training data and the validation data used were the same for both systems. We concluded that, despite the genetic fuzzy system being a newer process, it obtained better results than the neuro fuzzy system. Another conclusion was that, as the genetic fuzzy system can work with constraints, the membership functions setting kept the consistency of variable linguistic values.

A New Surfactant Flooding Model for Low Permeability Reservoirs

Surfactant as a successful Enhanced Oil Recovery (EOR) agent has been widely used in many mature reservoirs. This research focuses on the description of surfactant solution at low permeability condition. A new three-dimensional, two phase, three-component surfactant simulator is presented. The simulator is based on the non-Darcy flow characteristics of surfactant flooding in the low permeability formations. The change of threshold pressure and influences of surfactant on convection, diffusion, adsorption, and retention, are all considered. A new equation for the calculation of surfactant adsorption is employed, which can significantly promote the matching degree between the mathematical model and field practice. The design of this new simulator is to help the decision-making in the reservoir engineering analysis of surfactant EOR projects, to face the challenge of the design of injection schemes, to assist the surfactant screening, to screen and assess laboratory and field data and their effect on the performance predictions, and to find the optimal methods of field development.