Early Stages Of Field Development Research Articles

Formation damage challenges and solutions in cased hole gravel pack completions in deep offshore unconsolidated laminated sandstone formations in the Sakarya Field

A comprehensive experimental formation damage study for the Sakarya Field was conducted to identify production impairment mechanisms induced by operational fluids. The study reveals that the retention of operational fluids leads to irreversible reductions in gas permeability to a certain degree. This fluid retention is associated with the amount of loss and retention time of operational fluids into the reservoir, as well as the types of clays present in the gas bearing zone. Fluid retention damage is more severe for samples with lower permeability and higher silt content. While sandy plugs typically experience a reduction in permeability of less than 10%, low-permeability silty samples can exhibit reductions as high as 35%. The most effective approach to minimize this damage includes maintaining the lowest possible overbalance pressure, applying completion methodologies with minimal fluid invasion, and ensuring timely and effective cleanup. Another source of damage appears to result from acidic dissolution of native carbonate minerals and destabilization of delicate clays (e.g., chlorite). This leads to slight compaction and associated immediate reduction in permeability, reaching as high as 50% when combined with other operational fluid damage in some cases. In such environments, it is recommended to use a milder alternative acid solution that specifically targets the filter cake and debris around perforations, minimizing the dissolution of native carbonate minerals and interaction with clays. Due to the low uniaxial compressive strength (UCS) of the formation, evidence of sanding and proppant embedment was observed. To mitigate this issue, an optimum gravel pack design and execution during well completion is vital. Additionally, avoiding abrupt bean-up and bean-down during well tests and production will help limit sanding and proppant embedment. The novel experimental methodology and field implications derived from this study may serve as a guideline to solve formation damage challenges in similar fields facing similar issues. Initiating such detailed studies in the early stages of field development is critical to ensure maximum recovery from the least damaged and disturbed reservoirs.

METHODOLOGY FOR SELECTING A PROCESS OF ASSOCIATED PETROLEUM GAS UTILIZATION

The utilization level of associated petroleum gas in Russia and in the world is gradually increasing, due to introduction of legislative restrictions and due to realization of the high value of associated petroleum gas as a raw material and energy carrier. At the same time, the usage of dissolved gas is geographically heterogeneous and depends on many factors, including the stage of field development, the subsoil user, and others. The need to increase the level of rational usage of dissolved gas is facing complications in the implementation of relevant projects. The reason lies in the lack of a method for substantiated selection of the most efficient method of utilization in the absence of datum in the early stages of field development; high risks at high capital costs, which is especially noticeable for fields in the later stages.
 The state and subsoil users are interested in creating a unified and objective methodology for selecting the optimal method of associated gas utilization, which, in turn, should ensure the coordination of actions between the government and the oil and gas industry in achieving high efficiency in the development of oil fields and increasing the level of associated petroleum gas disposal. At the moment, there is no such a method, but a number of publications have been devoted to solving this problem.
 The article will outline the main stages and aspects of author’s work on the development of screening criteria tables of disposal methods and methodology for selecting the optimal option for the rational usage of dissolved gas. The work was carried out based on the results of studying the experience of implementing various technologies and the identified limiting factors and was proceeded using the methods of multi-criteria analysis (hierarchical method).

Optimization and Evaluation of Stabilizers for Tight Water-Sensitive Conglomerate Reservoirs.

The upper Wuerhe formation in the Mahu-1 play is a tight conglomerate reservoir that has characteristics of low porosity and low permeability. During the early stage of field development, it has been noticed that horizontal wells typically have a high flowback ratio and an extremely low oil production rate during the early production, and this is likely attributed to the water–rock interaction that causes the closure of generated hydraulic fractures. In this study, a stabilizer and its dosage in a fracturing fluid are optimized, and its effect on clay antiswelling and rock stabilization is evaluated. Experimental results indicate that a mixture of a salt and an inorganic cationic polymer can effectively inhibit the water–rock reaction by minimizing the clay swelling and compressing the electric double layer on the rock surface. The antiswelling rate of montmorillonite can reach 93.56%, and that of the reservoir rock powder can reach 75.32%. Meanwhile, Brazilian splitting tests are conducted to evaluate the mechanical property change of reservoir rocks before and after being submerged in fracturing fluids with different stabilizers. Compared to 4% KCl, which is currently used in the field, the new formula can enhance the breakdown pressure by more than 10% without increasing the cost. The findings of this work provide a solution for fracturing water-sensitive reservoirs and also establish a set of laboratory methods for optimizing stabilizers as fracturing fluid additives.

Differential evolution for early-phase offshore oilfield design considering uncertainties in initial oil-in-place and well productivity

• Differential evolution optimization of number of wells, plateau rate and NPV. • Multi-objective optimization considering ultimate recovery factor and NPV. • The NPV distribution average can be estimated with the average of the variables. • Method provides decision support to field planners in early field development. During the early phases of offshore oil field development, field planners must decide upon general design features such as the required number of wells and maximum oil processing capacity (field plateau rate), usually by performing sensitivity studies. These design choices are then locked in subsequent development stages and often prevent from achieving optimal field designs in later planning stages when more information is available and uncertainties are reduced. In the present study, we propose using numerical optimization of net present value (NPV) to advice field planners when deciding on the appropriate number of wells, maximum oil processing capacity (plateau rate) in a Brazilian offshore oil field. Differential Evolution (DE) is employed for solving the optimization models. The uncertainties considered are well productivity and initial oil-in-place, handled by (1) using the mean of the distributions and (2) Monte Carlo simulation. A multi-objective optimization was also formulated and solved including ultimate recovery factor in addition to net present value. The proposed method successfully computes probability distributions of optimal number of wells, plateau rate and NPV. If one wishes to compute the mean of such distributions only, for most cases it is adequate to run an optimization using the mean of the input values instead of performing Monte Carlo sampling. The multi-objective optimization allows to find field designs with high ultimate recovery factor and high NPV. In this case, the value of NPV is similar to the optimum NPV value when optimizing NPV only. The methods described could provide decision support to field planners in early stages of field development.

Ntegration of Petrophysical Analysis and Elastic Log Properties as an Input to Optimize the Development Wells Target in Unique Globigerina Limestone Gas Reservoir in Madura Strait

The Madura Strait PSC is located in the southern part of North East Java Basin with biogenic gas from Globigerina limestone Pliocene Mundu and Selorejo sequence as main target. At early stage of field development,understanding and knowledge about petrophysical and elastic properties of reservoir rock quality is required and very important. The petrophysical analysis provide properties such as clay volume, porosity, permeability, water saturation and mineral volume to separate reservoir and non-reservoir zone. The elastic rock properties such as acoustic impedance (AI), shear impedance (SI), velocity ratio (Vp/Vs), and Poisson’s ratio (σ) were generated to identify clay zone, gas and non-gas also focused to distinguish reservoir rock quality inside gas zone as an effective reservoir characterization. This research is done by utilize core data, quad combo logs from eleven wells and shear velocity from eight wells. The purpose of this research is to optimize development well target in Globigerina limestone gas reservoir, which have good to best reservoir rock quality shown with high porosity and permeability,low clay volume and water saturation. Results from this research indicate that lime mud matrix have significant impact in the reservoir rock quality. Meanwhile, gas saturation can affect the elastic properties due to this high gas saturation can decrease compressional velocity (Vp) value. Finally, the integration of petrophysical result and combination of elastic properties implementation can help in distinguishing the best reservoir rock quality, which contains gas that should be penetrated by the development wells

Information, robustness, and flexibility to manage uncertainties in petroleum field development

Development decisions for petroleum fields are costly and difficult because they involve long-term projects with complex systems and high level of uncertainties. Decision makers may reduce reservoir uncertainties with the acquisition of additional information or protecting the system against uncertainty with flexibility and robustness. Although often preferred, acquiring additional information may be insufficient to mitigate all uncertainties or may be suboptimal when compared to robustness and flexibility. This study proposes a decision framework to estimate the best approach to manage uncertainty at early stages of field development considering the combination of information, robustness, and flexibility. With a predefined set of uncertain scenarios and specialized production strategies optimized for representative models, we can automate the process. We identify the best way to manage uncertainties by assessing system sensitivity and what controls production strategy selection. We improve the traditional estimation of the expected value of information (EVoI), robustness (EVoR), and flexibility (EVoF), by accounting for all changes in the risk curve and weighing the decision maker's attitude. Our proposal was validated in a controlled environment where the reference response is known (a reference model, called UNISIM-I-R, that is not part of the uncertain ensemble, called UNISIM-I-D). The best approach to manage uncertainty in UNISIM-I-D combined features of robust and specialized strategies, resulting in a flexible strategy with robustness. This solution increased oil recovery and the economic return in UNISIM-I-R when compared to taking no action to manage uncertainty, but was suboptimal. These results agree with the rationale behind investing in actions to manage uncertainty (such as flexible and robust strategies), which is to mitigate risks or exploit upsides of uncertainty (i.e., they are intended to prevent or explore extreme outcomes). Investing in such actions is a risky decision in itself because they may not be needed, depending on the features of the real reservoir. Our results in UNISIM-I-D demonstrate the EVoI, EVoR, and EVoF are not additive. Our results in UNISIM-I-R reveal that inherent flexibility in operations (such as in drilling of horizontal wells) may mitigate some risks, reducing the EVoI, EVoR, and EVoF. Our proposal is a good starting point for more quantitative and objective decision-making at the early stages of field development and ultimately prevents discarding attractive solutions based on biases or insufficient metrics. Some improvements may be necessary for EVoI, EVoR, and EVoF estimates depending on the stage of the lifetime of the field, among other factors.

Determination of bubble point pressure and oil formation volume factor: Extra trees compared with LSSVM-CSA hybrid and ANFIS models

Successful field development relies on effective reservoir management, which, in turn, is, to a great extent, influenced by the knowledge of reservoir fluid properties and phase behaviour. Laboratory experiments, known as Pressure-Volume-Temperature (PVT) tests, are the most reliable sources of detailed information on reservoir fluid properties required for different recovery stages and methods. However, these laboratory experiments are costly and time-consuming. Also, the experimental data of reservoir fluids are not readily available in many cases, particularly in early stages of field development when such data are required for estimation of the in-place fluid volumes and/or design of enhanced recovery processes. For these reasons, the development of models for prediction of reservoir fluid properties, especially the bubble point pressure (Pb) and oil formation volume factor (Bo), has been an active area of research since decades ago. In this paper, we have used the effective machine learning approaches of Extremely Randomized Trees, also called Extra Trees (ET), Least Square Support Vector Machine (LSSVM) hybridized with the Coupled Simulated Annealing (CSA) algorithm, and Adaptive Network-based Fuzzy Inference System (ANFIS) to develop models for prediction of Bo and Pb. An extensive dataset of the essential reservoir and fluid properties comprised of initial solution gas-oil ratio (Rsi), gas specific gravity (γg), oil API gravity (API), and reservoir temperature (T), in addition to the target parameters, has been used to introduce the models. The main focus of this study is on the ET modelling method which we have used as a robust tool to predict the fluid properties of interest with high accuracy over wide ranges of the input features. The other two modelling techniques, i.e. LSSVM-CSA hybrid and ANFIS, have been used in this work to provide a basis for comparison and evaluation of the models. The predictions of the developed models greatly match the real data. Through detailed model evaluation and error analysis, it is shown that the ET model outperforms the other models in terms of accuracy and robustness (with very small mean absolute percentage errors of 0.099% and 0.917% for Bo and Pb predictions, respectively, over the total dataset), although all the developed models exhibit strong performance and comparably accurate predictions. Moreover, the developed ET models show a strong correlation between the predicted data and the target values with R2 > 0.99 in almost all cases over the training, test, and total datasets. The findings of this study can help to better understand the relative importance of the different reservoir fluid parameters typically used for the prediction of Bo and Pb. Based on this work, with the ET approach, Pb and Rsi have the highest importance in determining Bo and Pb, respectively, while temperature has the lowest significance in both cases. To the best of our knowledge, this work is the first Bo and Pb modelling attempt using the ET method. Additionally, we have applied the feature selection capability of the tree-based estimators to develop a new ET model for prediction of Pb using only two parameters (Rsi and γg); an outcome that is of particular importance in case of the lack of data on other parameters which are required in almost all the other Pb predictive tools and correlations reported in the literature.

Applying information technologies in identifying the features of deposit identification under conditions of different oil-and-gas provinces

This paper describes application of information technologies to reveal general regularities in target identification under conditions of various tectonic and stratigraphic elements from studying the influence of the volume of basic geological and field information onto the degree of identifiability of deposits. A minimal set of parameters has been established to characterize various geological system while conducting the identification procedure using a limited amount of information at the early stages of field development. An algorithm is proposed for determination of parameter weight to identify the parameters that have a prevailing influence on identifiability of development targets. A set of parameters that are neglectable due to various financial and organizational reasons has been established.

Hydraulic flow units' estimation from seismic data using artificial intelligence systems, an example from a gas reservoir in the Persian Gulf

In recent years, considering the reservoir pressure drop in productive wells, designing the optimal well trajectory for production and injection in enhanced oil recovery (EOR) plans requires to determine hydraulic flow unit (HFU) in the reservoir. HFUs can also be used for petrophysical zonation of reservoirs as well as permeability predictions in uncored intervals or zones with low quality core data of wells. In the present study we have tried to integrate 3D seismic data with well data in order to find a quantitative relationship between flow zone index (FZI) and seismic attributes through employing linear regression and artificial intelligence models. Using this approach, FZI can be predicted using the information which is propagated in the whole field and achievable in the early stage of field development and consequently a suitable HFUs model may be represented. To this end, the suitable attributes for FZI estimation were selected by stepwise linear regression from extracted acoustic impedance (AI) and sample based attributes. Afterward, three optimal intelligent systems including probabilistic neural network (PNN), multi-layer feed forward network (MLFN), and radial basis function networks (RBFN) were employed. The obtained results reveal that PNN is the most accurate estimator compared to MLFN, RBFN, and multi-attribute regression methods. In the final stage, PNN was applied to develop 3D hydraulic flow unit model for the reservoir section of the investigated carbonate gas field located in Persian Gulf.

Regional tectonic state and poro-thermo-elasticity analysis of near wellbore zone in field development plan: Utilization of an uncoupled approach

The main aim of this work is to investigate the effects of temperature and pore pressure on stability of wellbore wall, considering the wellbore spatial orientation and regional tectonic state of the field in which the well is drilled. An uncoupled approach was proposed in this research study. Although the combination of fluid and temperature diffusion can be intensely alter the pore pressure and temperature of the near wellbore zone, the uncoupled approach can be considered as a primary, fast and simple method for optimization purposes at the earliest stages of field development when the technical data/information to conduct a coupled simulation is limited. The data used for this study were collected from real, literature and simulation cases. The real data are from geological and geophysical studies of gas reservoirs in Siberia, Russia. The results show that the problem of wellbore breakout (shear failure) happens in the final stages of field development however, the hydraulic fracturing and fluid loss (tensile failure) are the most common problems at the early stages of field development. Increasing wellbore temperature increases the shear failure risk for any wellbore orientation and regional tectonic state however it decreases the risk of tensile failure by increasing the tensile strength of rock. Effect of zenith angle on shear and tensile failure of wellbore depends on the regional fault regime. At the regions with normal fault regime, vertical wellbores are more stable than horizontal and vice-versa for strike-slip cases. For reverse fault regime, there is an optimum wellbore zenith angle where the shear failure is minimum and tensile failure is maximum. The results are further considered not only from drilling point of view but also for hydraulic fracturing job and hot fluid injection in field production life. Real well data from gas condensate reservoir in normal fault regime was provided for comparison and model validation purposes, showing a good agreement.

Selling science: Resource mobilization strategies in the emerging field of nanotechnology

Pioneers in emerging scientific and technology fields face liabilities of newness at both individual and collective levels. Insights from the literature of institutional entrepreneurship and sociology of knowledge suggest that, to overcome this double hurdle, early entrants may want to participate in a field’s hot center and connect their ideas to multiple existing fields to broaden their audience. However, these strategies have their drawbacks too, and the payoff of these strategies also decreases as a field gains cognitive legitimacy. Moreover, both the positive and negative effects of these mobilization strategies are more pronounced for less-experienced scientists. Findings from a comprehensive database on grant proposals in the emerging field of nanotechnology confirm these propositions, suggesting that an effective mobilization strategy is a balancing act between isomorphism and differentiation, breadth and boundary maintenance, especially in early stages of field development.

Sand production assessment considering the reservoir geomechanics and water breakthrough

Sand production assessment is essential from the early stages of field development planning for completion design and later for the production optimisation. Unconsolidated and weakly consolidated sandstones are prone to fail at a low flowing bottomhole pressure during hydrocarbon production. To predict the critical flowing bottomhole pressure or a safe drawdown, a geomechanical model that integrates in situ stresses, rock mechanical properties, the well trajectory, reservoir pressure, the production plan and the depletion trend is required. For a given stress field, well trajectory and production plan, the rock strength index is a key parameter that has significant impacts on the sanding risk. This paper presents the results of a study investigating the potential of sand production from primary and secondary target reservoir rocks in a petroleum field in offshore Vietnam. A poroelastic analytical approach was used to investigate if sands will be produced from the open holes or perforations. The criterion of sanding was formulated to be the effective maximum principal stress to be greater than the effective rock strength. Observations of sanding or no sanding during drill stem tests (DSTs) were used to calibrate the sanding model to be used for sanding predictions of future production wells. The effects of reservoir pressure depletion on sanding risks were investigated using the stress arching theory. Since the water production from target reservoirs was observed in the nearby fields, the analysis was performed to investigate the effects of water production on rock weakening that may cause higher risks of sanding. The results showed low risks of sanding for majority of the reservoirs, with drawdowns as high as 3,000 psi at the original reservoir pressure. The drawdown was, however, required to reduce to 500 psi to produce sand-free after depleting the reservoir by more than 90% of its original pressure. The results of this study led to the decision of completing the wells without using sand control equipment and to avoid sanding by controlling drawdown for the life of the well.

When does brokerage matter? Citation impact of research teams in an emerging academic field

Through exposure to heterogeneous sources of knowledge, actors who broker between unconnected contacts are more likely to generate valuable output. We contribute to the theory of social capital of brokerage by considering the impact of field maturity. Using longitudinal data from the field of strategic management we find that the benefits of network brokerage are stronger during the early stages of field development and diminish as the field matures. The results of our study call for further research on the interplay between network structures and processes of field emergence.

Flow upscaling in highly heterogeneous reservoirs

AbstractIn the early stages of field development, there are many uncertainties and the current trend is to generate coarse-scale models so that many simulations can be run rapidly in order to determine the main sensitivities in a model. However, at a later stage, more data are available and there is less uncertainty in the model, so a more detailed modelling approach is desirable. In this paper, we discuss two modelling procedures which are suitable for different stages of the life of a field, and address the problem of upscaling at each stage. First, we consider a novel approach for generating coarse-scale models for evaluating uncertainty. When there is a large amount of uncertainty, the generation of fine-scale models is too time-consuming, and upscaling them by large factors may produce large errors. We demonstrate an alternative approach for modelling at a coarse scale, while preserving the heterogeneity of the fine-scale distribution, in such a way as to reproduce the fine-scale flow results. Secondly, we focus on more detailed geological models, generated at a later stage of field development. These models may comprise millions of grid cells, and may be highly heterogeneous. Such models require upscaling, but traditional methods may be very inaccurate. We have developed a method for upscaling using well-drive boundary conditions. Tests of this method show that it can reliably reproduce the fine-scale recovery in a range of models.

Identifying Reservoir Compartmentalization and Flow Barriers From Primary Production Using Streamline Diffusive Time of Flight

Summary We propose a novel approach that uses streamline-based drainage-volume computations using a "diffusive time of flight" to infer reservoir compartmentalization during primary production. Our approach consists of three steps. First, we perform a traditional decline-type-curve analysis of the primary production data to identify well communications and estimate the drainage volume of individual wells. Second, starting with a geological model, the drainage volumes of each well are recomputed with a streamline-based flow simulation. Finally, flow barriers and reservoir compartmentalization are inferred through a matching of the streamline-based drainage volumes with those from the decline-curve analysis. Our approach is completely general and can be applied to reservoirs in the early stages of field development and with very few wells. We demonstrate the power and utility of our proposed method using synthetic and field examples. The field example is from a field in the Gulf of Mexico. Starting with a reservoir model based on well-log and seismic data, reservoir compartmentalization and flow barriers are identified from 3 years of primary production response.

Screening of Geostatistical Reservoir Models With Pressure Transients

Summary A geostatistical reservoir study provides an ensemble of possible reservoir models, with a variability reflecting the uncertainty of the geology and fluid-flow properties. A production test links the static geostatistical model with dynamic fluid-flow data and thus provides possible means of validation and selection. We used a highly efficient 3D single-phase simulator to simulate pressure transients without compromising the fine-grid resolution typical for geostatistical models. This simulator was applied to Boolean and Gaussian geostatistical models that represent reservoirs consisting of heterogeneous fluviodeltaic deposits. Simulated buildup and interference tests were analyzed and related to 3D permeability and connectivity patterns. Effective well-test permeability was compared with 3D averages obtained from different volumes within the geostatistical model. The cases studied show that combining geostatistical models and well tests can reduce uncertainty with respect to geometric connections and the permeability distribution. However, the study also confirms that well tests have a limited capability to assess lateral continuity precisely and uniquely. Simulation of an interference test has the potential to screen the geostatistical model for high-permeability connections between wells. This pragmatic integration of pressure transients and detailed heterogeneous reservoir models through forward simulation provides a simple means to evaluate these models. It allows testing a model based on small-scale (core-plug) permeabilities and qualitative geologic information vs. routine field measurements representing large-scale hydraulic behavior of a reservoir. Introduction During the early stage of field development, production tests are the only data providing information about fluid flow in oil reservoirs and about permeability in the wider volume surrounding a well. At the same stage, construction of a geostatistical reservoir model is now a viable option. The main purpose of this model is to assess the uncertainty of reservoir performance resulting from incomplete knowledge of the heterogeneous reservoir. Geologic data and core measurements are honored at the wells, and models are created between wells that are statistically similar to those inferred from geologic analogs. These are static data, and subjecting the geostatistical model to verification on the basis of dynamic fluid-flow data (i.e., pressure-transient production tests) is a logical step. The pressure transient reaches faraway boundaries in a relatively short time.

Producing From Exploration Wells

Temporarily producing a well or wells allows extended testing for evaluating a reservoir before incurring large additional drilling expenses to develop afield. It is also useful for determining the capacity and specific process a permanent production facility should have if one is justified. As an additional benefit, such production provides cash flow early in a field's development cycle; even at the exploration stage. For these reasons, the use of temporary facilities for early production and extended well testing is increasing, both on- and offshore. In response, standardized modules and process skids that can be kept in stock to shorten delivery lead time were developed. As a result, the time typically needed to design, fabricate, and install a 10,000- to 40,000-BOPD early production facility (EPF), such as the one in Fig. 1, has been reduced to 14 weeks. This standardization permits capacity to be added or cut back as required, makes mobilization faster and easier, lowers upkeep and maintenance costs through improved reliability, and often saves transportation costs by allowing shipment from fabrication site to wellsite by common carrier. An EPF constructed from such standardized modules can be configured to fit practically any available space. This allows a facility for offshore use to be installed on a semisubmersible, jackup rig, barge, floating production platform, production jacket, or tanker. For use on land, a modular EPF can be mounted on skids or trailers. If the EPF must be transported a relatively long distance or installed at a remote site, the overall time required will exceed the typical 14-week period, but not by a large margin. As an example, an EPF made up of standardized modules was recently designed, prefabricated, and transported to and installed on a semisubmersible rig drilling in the Machar field in just 19 weeks from the time the operator approved the project. The Machar field is on Block 23/26a in279 ft of water in the U.K. sector of the North Sea [110 miles east of Aberdeen. This EPF, which is processing the produced fluids from two wells for reservoir evaluation, has a standard capacity of 20,000 BOPD. However, owing to customization and the properties of the Machar crude, actual sustained production is 30,000 BOPD, with two-stage separation of gas and oil. The gas is flared with two 60-ft booms with low-pressure flare tips and a high-pressure flare tip on the 150-ft-high derrick. Processed oil is stored on a dynamically positioned tanker that is linked to the EPF on the semisubmersible rig by a0.62-mile subsea flow line. This discussion has concentrated on the use of modular EPF's to provide reservoir evaluation information and cash flow during exploration and early stages of field development. However, it should be noted that EPF use is not limited to such situations. For example, it is not uncommon for an EPF to be used to produce a marginal field offshore because a full-scale permanent production facility would be prohibitively expensive in relation to the anticipated return on investment. In this type of application, the EPF is often called a mobile production facility (MPF). Whether called an EPF or MPF, this fast-track approach minimizes negative cash flow while allowing a decision on field development to be made at a later time. bblx1.589 873 E-01 =m3 ftx3.048* E-01 =m milex1.609 344* E+00 =km *Conversion factor is exact. P. 871

Major Influences of Clastic Reservoir Anatomy on Oil Recovery

Even in simple layer cake reservoirs, contrasting strata, pinchouts, and impermeable intercalations commonly impair vertical sweep efficiency. However, extensive impermeable streaks may prevent coning of water or gas. For many reservoir configurations, certain features can be either favorable or unfavorable for oil recovery depending on accumulation conditions, mobility ratio, structural dip magnitude and orientation, and applied drainage and injection schemes. Although this complicates relating classification systems of recovery efficiency directly to geological aspects, clastic reservoirs commonly display predictable production behavior closely related to environment of deposition. For example, fluid flow in deltaic reservoirs composed of sand bodies with contrasting permeabilities is dominated by pathways of least resistivity. These occur in typical patterns related to paleogeographical trends. The threat of local cusping, coning, and breakthrough of water or gas dictates careful planning of locations, completions and production levels of individual wells. Extreme anisotropy is often associated with low net-to-gross [open quotes]labyrinth[close quotes] reservoirs deposited in coastal plain environments. Overall connectivity may be attained at net-to-gross levels of between 0.3 and 0.4, but major vertical and lateral discontinuities will exist on a well-to-well scale. Sweep efficiency is strongly influenced by sand body trends relative to dip orientation, and specific well patterns aremore » required. Reservoir simulation input should preserve reservoir architecture and correctly incorporate no-flow boundaries and intercalations. Probabilistic modeling systems using representative sand-body geometry databases can provide estimate of connectivity and simulation input at an early stage of field development. The crux of the matter is the prediction of production behavior for alternative development plans to reduce the negative influences of reservoir heterogeneity.« less