bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Upscaling Approach for Highly Heterogeneous Reservoirs
Authors: Zhang P. , Pickup G. E. , Christie M. A.
Published: December 2007

Upscaling in highly heterogeneous reservoir models is a very challenging procedure, despite much research having been carried out over the past few decades.The fluid flow depends on the well locations, and crossflow may be significant. Traditional upscaling approaches such as the pressure solution method with locally applied boundary conditions, may be highly inaccurate. In two-phase systems,such as waterfloods, accurate reproduction of the flood front is also problematic.Two-phase upscaling is often impractical,but using only traditional single-phase upscaling may lead to large errors.

In this paper we demonstrate how conventional upscaling approaches may produce erroneous results and suggest a simple alternative.The new method uses boundary conditions based on the actual well pressures and solves the single-phase pressure equation over the global fine scale geological model.Inter-block transmissibilities and upscaled well connection factors are then computed. By using the appropriate boundary conditions,single-phase flow is accurately reproduced,and therefore the accuracy of two-phase flow at the coarse-scale is greatly increased.

We have verified that the new method may be applied to two-phase, highly heterogeneous reservoir models, including models with multiple relative permeability curves and significant gravity effects.We have also applied the method to the benchmark model of the SPE 10th Comparative Solution Project(1.1 million cells, unstable flood). The results show good agreement with the fine grid solution provided by Landmark using a parallel simulator.

As models of tens of millions of grid cells are now solvable on a PC in an hour, this method is a feasible approach for achieving highly accurate upscaled models. This method is particularly appropriate for later stages of field development, when models are large and accurate flow simulation is required.
Performance and Emissions Studies of a Car Engine Fueled with Gasoline and CNG
Authors: Aslam M. U. , Masjuki H. H. , Kalam M. A.
Published: December 2007

The emergent alarm about the fast depletion of petroleum-based fuels and the environmental pollution caused by their combustion has been a compelling incentive to all researchers to find out the ways to use environmentally friendly and renewable resources of energy and also by technologies to increase vehicle energy efficiency. CNG (compressed natural gas) is the most desirable alternative fuel option to the researchers today for facing the energy crisis and environmental pollution problems properly. This is because of its availability, low exhaust emissions, superior performance and longer engine service life. Malaysia also trying to diversify its automotive fuel options by introducing new mono fuelled CND/DI (direct injection compressed natural gas) engine for utilizing the substantial advantages of CNG fully as an automotive fuel. In the present study a bi-fuel proton car engine has been run with gasoline and CNG and the performance and exhaust emissions of the engine are analyzed & compared. This result will be used as a basis for examining the performance and emissions of Malaysian new CNG/DI engine in future. Present study also focuses on the Malaysian mono fuel CNG/DI engine. From the experimental results, it is found that CNG produced less power, consumed less fuel per kwh and emitted less CO, CO2, HC and more NOx compared to gasoline. It is suggested to build up lighter CNG storage tank and widespread networks of CNG supply stations through out the country for general acceptance of CNG as an automotive fuel.
Modeling of Pre-Gel Aggregate Growth During the Gelation of a Polyacrylamide-Chromium(III) Acetate Gel System Using the Theory of Branching Processes
Authors: Cheng M. , Wang C. , McCool C. S. , Green D. W. , Willhite G. P.
Published: December 2007

Models that describe the pre-gel aggregate growth during the gelation of a polyacrylamide-chromium(III) acetate gel system are presented. Using the theory of branching processes, two models were developed to estimate the bulk gel time of a gel system and the molecular weight averages and distributions of pre-gel aggregates as functions of reaction time and initial conditions. A multi-angle laser light scattering instrument was used to determine the weight-average molecular weights of the pre-gel aggregates as a function of reaction time. Good agreement between the experimental data and the model results was obtained.
Permeability Prediction Using Pore Throat and Rock Fabric: A Model From Indonesian Reservoirs
Authors: Jaya I. , Sudaryanto A. , Widarsono B.
Published: December 2007

There is no easy way to estimate permeability from well logs. Porosity alone does not serve as a good predictor of permeability. Various empirical approaches have been commonly used to estimate permeability. The more parameters used in the algorithm the more impractical the formula. In fact, there are no causative relationships among the calculated parameters. Recent developments are marked by the use of pore throat size distribution for relating porosity to permeability (Winland and Pittman equations). The equations are theoretically correct but they are actually established for estimating pore throat size distribution and are not intentionally developed for the purpose of permeability prediction for uncored wells. In this light, it is this study that emphasizes the use of Windland and Pittman equations for permeability prediction and is the first study using samples from Indonesian reservoirs.

This study was carried out to improve the accuracy of permeability prediction of the traditional permeability-porosity relationships in uncored wells with particular attention given to low permeability datasets. Correlations between radius pore-throat aperture radii and porosity-permeability, using 315 core-plugs taken from Indonesian reservoirs, have been established. Application of the correlations shows that accuracy of permeability prediction is significantly improved when pore throat radii were incorporated. The study also take into consideration rock fabrics of the core-plugs on the basis of mercury saturation percentiles. For practical consideration, the correlations are also expressed in form of nomographs so that it can be used easily by engineers and petrophycicists. In using the nomographs, the input variables (pore throat and rock fabric) can easily be derived only from drill cutting samples underlining the practicality of the approach resulted from the study.
Performance Analysis of Compositional and Modified Black-Oil Models for a Rich Gas Condensate Reservoir
Authors: Izgec B. , Barrufet M. A.
Published: December 2007

The modified black-oil model (MBO) was tested against the fully compositional model and performances of both models were compared using various production and injection scenarios for a rich gas condensate reservoir.

We evaluated the performance of MBO model by investigating: the effects of black-oil PVT table generation methods from a tuned equation-of-state, oil-gas ratio (OGR) and saturation pressure versus depth as initialization methods, uniform composition versus compositional gradient with depth, location of the completions, production and injection rates, kv/kh ratios, and vertical wells versus horizontal wells.

Contrary to the common belief that OGR versus depth initialization gives better representation of original fluids in place, initializations with saturation pressure versus depth gave closer original fluids in place considering the true initial fluids in place are given by the fully compositional model initialized with compositional gradient.

Unrealistic vaporization in the MBO model was encountered in both, production by natural depletion and gas cycling. The changes in oil-gas ratio of the recyled gas showed that, it is not possible to accurately represent the changing PVT properties of the recycled gas with a single PVT table. Unrealistic vaporization also led to different arrival times for the displacement fronts and different saturation profiles for the near wellbore area and for the entire reservoir for the two models even though the production performance of the models was in good agreement.

The MBO model representation of compositional phenomena for a gas condensate reservoir proved to be adequate for full pressure maintenance, reduced vertical communication, vertical well with upper completions, and for horizontal well producers.
History Matching Using Probabilistic Approach in a Distributed Computing Environment
Authors: Yadav S. , Srinivasan S. , Bryant S. L. , Barrera A.
Published: December 2007

The focus of the paper is to present a novel methodology for delineating multiple reservoir domains, for the purpose of history matching in a distributed computing environment. A fully probabilistic approach to perturb permeability within the delineated zones is implemented. The combination of robust schemes for identifying reservoir zones and distributed computing significantly increase the accuracy and efficiency of the probabilistic approach.

The information pertaining to the permeability variations in the reservoir that is contained in dynamic data is calibrated in terms of a deformation parameter rD. This information is merged with the prior geologic information in order to generate permeability models consistent with the observed dynamic data as well as the prior geology. The relationship between dynamic response data and reservoir attributes may vary in different regions of the reservoir due to spatial variations in reservoir attributes, well configuration, flow constrains etc. The probabilistic approach then has to account for multiple rD values in different regions of the reservoir.

In order to delineate reservoir domains that can be characterized with different rD parameters, principal component analysis (PCA) of the Hessian matrix has been done. The Hessian matrix summarizes the sensitivity of the objective function at a given step of the history matching to model parameters. The eigenvectors obtained during the PCA are suitably scaled and appropriate grid block volume cut-offs are defined such that the resultant domains are neither too large (which increases interactions between domains) nor too small (implying ineffective history matching).

Since the domain delineation process yields zones that are least correlated with each other, each rD parameter can be optimized independently and simultaneously using individual nodes of a cluster of computers. Upon convergence, the perturbed regions are put together and the history match is verified. The proposed approach results in a set of independent tasks of equal magnitude and thus is particularly suited for distributed computing.
A Mechanistic Study of Naphthenate Scale Formation
Authors: Shepherd A. G. , Thomson G. B. , Westacott R. , Sorbie K. S. , Neville A.
Published: December 2007

Static bottles tests have been conducted on model naphthenic acid solutions with the objective of studying the mechanisms of naphthenate "scale" formation. Various experimental sensitivities were analysed such as initial pH, cation type and concentration in the aqueous phase, naphthenic acid type and concentration in the oil phase. Data has been obtained for the deposits formed from sodium, calcium and barium rich aqueous phases and their combinations. Trends in precipitate mass as well as the composition of the solid deposits obtained from X-Ray diffraction (XRD) and electron microscopy/energy dispersive x-ray (ESEM-EDX) are presented. The effects of cations on bulk and surface properties such as viscosity, emulsion stability and interfacial tension are also shown. These results contribute to the understanding of naphthenate deposition mechanisms under lab conditions.
Stimulation Challenges and Solutions in Complex Carbonate Reservo
Authors: Kumar P. S. , Gisbergen S. V. , Harris J. M. , Al-Naabi A. M. , Murshidi A. , Brady M. E. , Ferdiansyah E. , El-Banbi A. , Al Harthy S.
Published: December 2007

This paper details the challenges of stimulation in one of the fields in North Oman. The field is a mature, heavily faulted and fractured carbonate reservoir on water flood where acid stimulation carries an inherently high risk of inducing several fold increases in water production. Acid placement challenges are immense as the fracture networks impart massive permeability contrasts and are most often the principal conduits for "premature" injection water breakthrough. We present field data of acid stimulation treatments on cased hole, oil producers as well as open-hole horizontal injectors using a novel self-diverting acid system. This fluid has been recently applied in other reservoirs but to date, none of these applications have held the same magnitude of challenges and barriers to successful implementation of stimulation treatments. We present numerous field studies which identify self-diverting acid systems as a key solution, together with best practices in candidate selection (through reservoir logging evaluation) and coiled tubing placement methodology, in providing consistent improvement in net hydrocarbon well productivity and enhanced injection profile for reservoir management. In addition we present results of a new surfactant based self-diverting system and compare the results to conventional polymer based treatments in this field. The results are indicative of a further improvement in success ratio of acidizing treatments. Similar methodology and fluid systems are applicable in other complex fractured reservoirs where acid placement and minimizing water production present the principal challenges. Moreover, as reservoir management becomes an ever-increasing concern, we present a treatment methodology to enhance productivity, reduce water cut and optimise reservoir sweep, all of which reduce the overall lifting costs.
After-Closure Analysis to Determine Formation Permeability, Reservoir Pressure, and Residual Fracture Properties
Authors: Soliman M. Y. , Craig D. , Bartko K. , Rahim Z. , Adams D.
Published: December 2007

A minifrac test is usually performed before a fracture stimulation treatment to calculate formation and fracture properties. Recently the analysis techniques were extended to the after-closure period. The after-closure data are analyzed to calculate formation permeability and reservoir pressure.

Technology developers have hypothesized the existence of either pseudo-radial or linear flow behavior during the after-closure region. Identifying the presence of the flowing regime is an awkward process at best. The roots of the linear flow equations are different from those of the pseudo-radial flow equations. Many tests do not follow either flow regime.

In this paper, we have created a general approach for analysis of after-closure pressure decline data. Because the determination of the flow regime and type of fracture depends only on time and monitored pressure, the analysis may even be performed in real time. The technique determines whether sufficient data have been obtained to perform a reliable analysis. The calculated parameters would be used to update the fracture design and, in turn, for performing the fracture treatment.

The new technique is simpler and more generalized than what currently exists. The technique initially determines whether analyzable data exist. It shows that three flow regimes may dominate the after-closure region, depending on the reservoir properties and residual fracture conductivity. The technique presented not only determines the type of regime, and consequently, the type of residual fracture, it also determines the formation permeability and reservoir pressure.

There is no reason to restrict the application of this test to minifrac test analysis. We believe the approach is also applicable to analysis of data after performing a fracture stimulation treatment. A numerical simulator was used to model the pumping and closure process and to validate the new approach.

The paper also presents a detailed discussion and analysis of several field cases, demonstrating the various flow regimes and, ultimately, the validity of the developed technique.
Calculating Derivatives for History Matching in Reservoir Simulators
Authors: Rodrigues J. R. P.
Published: December 2007

The use of gradient-based optimization methods in automatic history matching requires that the reservoir simulator provides the necessary derivative information in the most efficient way. The implementation of these techniques in existing complex simulators is a difficult task, however. This paper describes the implementation of the forward and adjoint methods for derivative calculation in a full-featured adaptive implicit black-oil simulator. To show how the derivative calculation methods can be used even outside the framework of standard optimization algorithms, a new algorithm for automatic history matching, based on the truncated singular value decomposition, is proposed. Application to simple synthetic cases shows promising results.
Multiscale Process Coupling by Adaptive Fractional Stepping: An In-Situ Combustion Model
Authors: Younis R. , Gerritsen M.
Published: December 2007

We propose a time-stepping methodology for in-situ combustion simulation that is designed specifically to accommodate the various physical sub-processes, including conduction, advection, and kinetics, that have widely varying time-scales. The approach combines operator splitting with fractional time-stepping. The method is applied to a scaled form of the governing equations. We derived seven independent scaling parameters in the in-situ combustion process, representing ratios of heat capacity, mass transfer and heats of reaction.

We provide a proof of concept for one particular splitting and fractional step method that we found to be intuitive. In each time-step of this scheme, we solve the pressure equation semi-implicitly. Conservative accumulation treatment is assured by elimination at the Jacobian level. This is followed by an explicit solve for temperature, where a second elimination is performed to de-couple accumulation terms from the remaining concentration equations. The concentration equations are then integrated in a fractional- step, additive-splitting fashion. This means that reactions are separated numerically from the concentration advection- reaction equations. The overall solution for concentrations is obtained by performing a sequence of solves for reactions alternating with pure advection. A local fractional time-step size for either sub-process is introduced, and may be varied according to the local physics. Finally the global time-step solution is composed in an accurate fashion out of the sub-process solves.

To test the method a couple of test problems were designed for which the parameters are given in full detail so that it can be used for inter-code comparisons.
Binary Decomposition of Three-Term Seismic Inversion Data to Estimate Recoverable Hydrocarbon Volumes
Authors: Engelmark F.
Published: December 2007

Three-term seismic inversion volumes can define key reservoir properties such as porosity and water saturation that together define the hydrocarbon pore volume. The problem is that the vertical resolution of the elastic data is limited to, at best, approximately 10 m. That means the inversion volumes actually represent elastic properties of a net-to-gross (N/G) with unknown porosity and saturation in the net.

The binary decomposition is described by a model that shows how the elastic data can be decomposed into the properties of the reservoir rock, typically sand, and properties of the non-reservoir rock, typically shale. Given a production scenario, the recoverable hydrocarbon volumes can be estimated directly from the seismic traces through the process of inversion, creation of support data, binary decomposition, hydrocarbon pore volume estimation, and seismic trace volume sampling.
Fluid Transfer Mechanism Using Geochemistry in Shallow Oil Zones of Bahrain Oil Field
Authors: Murty C. R. K. , Zubari H. K. , Beeunas M. A. , McCaffrey M. , Thompson K. F.
Published: December 2007

Geochemical data of oil integrated with geological and engineering data have contributed to an understanding of the mechanism and relative timing of hydrocarbon emplacement in shallow oil zones (Rubble, Ostracod & Magma) of Bahrain's Awali oil field. These zones contain heavy as well as light oil. It is observed that the different oil types reside in different reservoir compartments. To efficiently develop and produce from these reservoirs, it is required to know the current distribution of the oil types and whether they result from different charging histories (gradations developed during initial or late stage migration) and or post-emplacement alteration (i.e. water washing, biodegradation, gas stripping, gravity segregation or de-asphalting).

The primary objective of the study was to determine the vertical and lateral continuity of the reservoir intervals to geographically identify areas for development drilling and EOR processes. A geochemical study involving an advanced gas chromatography technique was used which included: (a) comparison of abundance of "inter-paraffin peaks" between the different oil samples, (b) determination of the magnitude of the compositional differences between the oil "Star Diagrams" and "Cluster Diagrams", and (c) "Slope Factor Analysis" where the relationship between molar concentration and molecular weight (carbon number) are compared between the oils.

The Geochemical evaluation provided compositional data that helped to: Characterize the difference between the oils.Verify reservoir compartment-talization.Reveal the level of biodegradation, charging fluid type and relative charge histories for the different fluid types.Identify the geographical distribution of the different fluid types and their relation to potential migration pathways (e.g. faults).

In addition to providing information concerning the lateral continuity within specific reservoir intervals and vertical continuity between intervals, the geochemical data also indicate three charging events with oils of differing thermal maturity: Primary: Charges of extremely immature oil were introduced along a nearly linear path which traverses the field from SE to NW. These lines could be the major fault (N-S) and fractures providing initial migration paths.Secondary: Oils of increasing maturity (mixtures of light & heavy oil) were introduced progressively, as the basin subsided and the oil source matured. It is possible that the light liquids condensed from gas at the sites where they presently occur, the oils acting as a stripping liquid.Tertiary: (Emplacement of highly mature oil). This process has occurred predominantly in the Mauddud oil bearing formation, produced primarily close to the perimeter of the field.
History Matching of Heavy-Oil Production for Comparing New Approaches to Generating Reservoir Property Distributions, West Coalinga Field, California
Authors: Brame S. E. , Castle J. W. , Fawumi O. K. , Falta R. W.
Published: December 2007

Reservoir simulation of steam injection into heavy oil sands of West Coalinga Field in California has been conducted to assess suitability of different permeability distributions generated from geological and fractal modeling processes. Permeability distributions in each model were derived by integrating stratigraphically controlled models with core data provided by Chevron Production Company. Three distinct distributions were generated for each lithologic group: facies tract, facies group, and a fractal distribution of the facies group. The grid design is based on stratigraphic architecture of depositional facies. Construction of these models involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization.

Numerical simulation of steam injection into three adjacent 5 spot well configurations was used to assess suitability of each model. Injection and production histories of wells in the study area were simulated, including shutdowns and the occasional conversion of production wells to steam injection wells. The framework provided by the facies groups yielded a more realistic representation of reservoir conditions than facies tracts, which is revealed by a comparison of history-matching results. Permeability distributions obtained using the fractal model predict the high degree of heterogeneity within reservoir sands of West Coalinga Field. Modeling results indicate that predictions of oil production are strongly influenced by the geologic framework and by the boundary conditions.

Improved predictions of interwell reservoir heterogeneity have the potential to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain several billion barrels of reserves in the San Joaquin Valley.
Reservoir Rock Typing in a Giant Carbonate
Authors: Varavur S. , Shebl H. , Salman S. M. , Shibasaki T. , Dabbouk C.
Published: December 2007

Lithofacies classifications are a purely geological grouping of reservoir rocks, which have similar texture, grain size, sorting etc. Each lithofacies indicates a certain depositional environment with a distribution trend and dimension. Petrophysical groups are classified by Porosity, Permeability, Capillary Pressure and Pore throat size distribution. A Rock Type combines both these classifications by linking petrophysical properties and lithofacies as part of the reservoir rock type definition. It has been previously shown that the static rock types are not always representative of multi-phase flow behavior in the reservoir.

In this paper, we will present evolution of the rock types scheme within ZADCO. We discuss criteria used to define reservoir rock types in the current scheme and its limitations. The objective of the proposed rock type scheme is to address shortcomings identified with the current one in use and is based on the following criteria: Each Rock Type can be characterized by similar depositional and diagenetic environment■Each rock type has a typical and unique set of Pore Throat Size Distribution curves.■Each rock type has similar set of Capillary Pressure/Relative Permeability curves at a given wettability.■Porosity/Permeability overlap is minimal between different rock types.■Rock types can be predicted with satisfactory accuracy using logs in uncored wells.■Spatial 3D distribution of the rock types is predictable within a well-defined geological framework.
Use of Genetic Algorithm to Predict Minimum Miscibility Pressure (MMP) between Flue Gases and Oil in Design of Flue Gas Injection Project
Authors: Emera M. K. , Sarma H. K.
Published: December 2007

There is an increasing global awareness of the detrimental effects of industrial flue gases on the environment. As a consequence, much emphasis is being placed to harness flue gases that contain high CO2 concentrations and sequester them in suitable geological formations. A plausible means of sequestrating flue gases is to inject them into petroleum reservoirs while also enhancing oil recovery. An a priori understanding of the pressure at which various flue gas components, notably CO2, become miscible with reservoir fluids is critical to the design and implementation of a flue gas injection project.

A new genetic algorithm (GA)-based correlation has been developed to estimate the flue gas-oil MMP. In developing this correlation, the GA software developed in our earlier work has been modified to account for various component gases in the flue gas stream. The correlation estimates the MMP as a function of the injected gas solvency in the oil. The solvency, in turn, is related to critical properties of the injected gas. The correlation has been successfully validated against published experimental data and several correlations in the literature. It yielded the best match with an average error of 4.7% and a standard deviation of 6.3%, followed by Sebastian et al. correlation with 13.1% error and 22.0% standard deviation and Alston et al. correlation with 14.1% error and 43.2% standard deviation.

An advantage of the GA-based correlation over other correlations is that it can be used for gas mixtures with higher N2 concentrations (tested up to 20 mole%) and with non-CO2 component concentrations of H2S, N2, SOx, O2, and C1-C4 up to 78 mole% with a higher accuracy. Equally important, it could be a useful tool when experimental data are not available and/or when developing an optimal and economical laboratory program to estimate the flue gas-oil MMP.
Integrated Reservoir Studies Optimize Hydraulic Fracturing and Post-Frac Well Performance: Case Studies in Saudi Arabian Gas Sandstones
Authors: Raba'a A. S. , Rahim Z.
Published: December 2007

Proposal

This paper presents a methodology for an integrated reservoir study to identify different facies in the reservoir, select perforations interval and type of hydraulic fracture, understand pre- and post-fracture reservoir performance, and optimize fracturing treatments and reservoir development. The target formation is mainly from a Permian eolian ‘Unayzah-A gas bearing sandstone reservoir which is highly heterogeneous and poorly consolidated that requires a systematic and integrated assessment prior to its development.

Integrated reservoir studies utilizing engineering and petrophysical data showed the complexity and heterogeneity of the ‘Unayzah-A reservoir. The reservoir constitutes of clay mineral (illite) and hence it is highly susceptible to formation damage associated with drilling fluids. In order to remove damage, control sand production, and improve productivity, all gas wells are routinely fracture stimulated employing screen or screenless completion.

This paper provides a summary of the reservoir and fracture treatments focusing particularly on the fracture design, execution, fracture modeling, and post-treatment production analysis from the recently completed wells. A comprehensive data set of logs, pre- and post-fracture pressure buildup tests (PBU's), drill stem tests (barefoot and cased hole DST), and detailed fracture modeling are presented to demonstrate the fracture performance in this complex eolian dune reservoir environment.

Estimation and interpretation of reservoir pressures, fracture geometry, and transient tests from these wells indicate possible water-zones compartmentalization, reservoir continuity, and depletion as primary drive mechanisms.

This paper shows that understanding reservoir quality and characteristics, using focused reservoir studies, leads to successful completion results and optimum development. The study identifies the dominant flow unit, eliminates unnecessary perforation intervals, determines stimulation treatment type and size and optimizes cost for overall field development.
Resolution of a Multi-Set, Strike-Slip Dominated Fault System, Identified from 3D Seismic, in Early Cretaceous Carbonate Reservoir Sequences of a Giant Offshore Field in Abu Dhabi
Authors: Edwards E. , Al-Rougha H. B. , Sit H. , Sultan A. , Khouri N.
Published: December 2007

Recent mapping of fault patterns from picked surface attribute analysis (‘difference’ maps, spectral decomposition, isochron maps) and time slices over a giant offshore field in Abu Dhabi has recognized a complex multi-set pattern of faults at reservoir level. As well as providing additional seismic scale faults, linear features (proposed subseismic faults and fracture systems) have been identified. These patterns are best described in terms of strike-slip geometries; however, many display components of both dip-slip and strike-slip over their movement history. In different parts of the field dominant fault directions displaying dextral transtension, dextral transpression, trapdoor hinge faulting and oblique-slip keystone graben generation are observed. Fault throw statistics and segment growth history in the most important mapped zones typify components of strike-slip along with local shear and segment termination at cross-fault zones. The prevalent fault trends are roughly orthogonal NE-SW and NW-SE systems that dissect the field. Superimposed on this geometry is an array of distinctly en-echelon WNW-ESE and WSW-ENE structures that link to steep zones at deeper levels. Within sub-regions of the field other trends are also present, including NNE-NNW to N-S, NNW-SSE and E-W. These sets do not form a radial pattern; they are distributed spatially within field domains and involve complex systems and layer-related rheologically controlled deformation.

Comparison of the mapped lineament pattern with core-derived fracture orientation data shows that all sets identified in the field from seismic are present within the overall fracture strike system within the wells. Field-wide, domains where transtension and transpression dominate, as well as more dip-slip dominated areas can be mapped out. Core scale fractures tend to display a component of strike-slip within the bulk strain field-wide, as evidenced by steep or sub-vertical fracture intersections. Newly identified lineament zones allow better understanding of high intensity fractured wells previously mapped distal to known faults
Origin and Potential of Unconventional Jurassic oil reservoirs on the northern Arabian Plate
Authors: Goff Jeremy
Published: December 2007

Unconventional oil reservoirs exist in deep, overpressured, fractured carbonate source rocks, and in adjacent dolomitised carbonate platforms, in the Jurassic Gotnia Basin on the northern Arabian Plate. These reservoirs are an important potential future resource for the region once the low risk prospect inventory in conventional plays is drilled out, and production from their reservoirs inevitably reaches a plateau. An estimated 5 – 10 trillion barrels of oil have been generated in the Jurassic source kitchen; recovery of just 0.5% of this volume would yield substantial oil reserves. A high proportion of the generated oil has probably been retained in secondary porosity within the Jurassic Petroleum System, beneath an evaporite caprock. Pore pressure gradients approaching 1 psi/ft during oil generation (at pore pressures of 10,000 – 20,000 psi), and localized folding in Late Jurassic, Turonian and Late Tertiary time, have created a complex fractured reservoir system within the Jurassic source rocks and interbedded carbonates. Sustained production from the source rock reservoirs may only be possible in areas where oil filled microfractures are able to recharge large connected permeable tectonic fractures during pressure drawdown. Dolomitising fluids and oil have migrated into carbonate platforms underlying, and flanking, the source kitchen. Fluid inclusion studies indicate that dolomitisation occurred at temperatures of 80 – 140 deg C from pore waters with salinities of 100,000 – 250,000 ppm, locally creating world class oil reservoirs (sealed by tight limestones) seen at outcrop in the Zagros Mountains on the deformed eastern margin of the basin. Successful exploration and development of the Jurassic reservoirs will be challenging - requiring pre drill seismic imaging of fracture systems and of laterally discontinuous porous dolomite units, application of unconventional wells in challenging drilling environments, and careful reservoir management during production to achieve commercial recovery factors.
Enhancing Marginal Field Development Economics by Leasing Operated Production Facilities
Authors: Maclean A.
Published: December 2007

Innovative technical advances are now enabling operators to consider development of fields previously identified as uneconomic or marginal. However such projects can still fail to progress since development using a traditional engineering, procurement and construct (EPC) approach does not always meet the required targets for economics, risk and timescale necessary for approval to proceed.

In this paper the author will detail how the use of fit-for-purpose production facilities mobilised on a leased, operated and maintained basis now offers an alternative approach to the provision of a field production solution. This approach enables operators to limit their initial set-up and infrastructure costs at the front end of a project, to gather additional information on the performance and productivity of their wells and to make a more informed decision on the future of the field. As a result, operators can keep both their project and capital risk exposure to a minimum.

By achieving this production on a fast-track basis, revenue from the sale of produced well fluids is generated early. Combined with the low initial cost and lower capital risk of this approach, the economic viability of progressing an asset to full scale production is further enhanced. Based on this sequential investment model, a real option analysis of the overall field development plan can therefore make a project viable, even if the overall project net present value (NPV) appears marginal using more traditional methods.

In conclusion the paper will present technical solutions for the various field evaluation and production stages of a full field development utilising the leased facility approach, associated commercial models and case studies for recently completed projects.
Structured Uncertainty Assessment for a Mature Field through the Application of Experimental Design and Response Surface Methods
Authors: Salhi M. A. , Van Rijen M. , Wei L. , Dijk H. , Alias Z. , Upadhyaya A. , Lee H.
Published: December 2007

This study covers one of the largest and oldest oil fields in Oman. Despite over 35 years of production through various drive mechanisms, there remains an opportunity to realize additional value in the field.The scale and complexity of the uncertainties associated with such opportunity necessitates the use of experimental design and response surface methods to provide a framework for evaluating sensitivities and estimating impact of uncertainties on field performance.

Since data sometimes are incomplete or inconsistent and measurements are ambiguous or inconclusive, the representation of reservoir and geological parameters are often sub optimal. This is especially true for heterogeneous fractured reservoir, such as this field, where the number and range of uncertainties is large.This paper presents the application of experimental design and response surface methods to the field development study of this field.

The methodology uses an integrated approach, where cross discipline data is evaluated early in the study to identify and quantify uncertainties with the highest impact. After static and dynamic data are reviewed and quality checked, an initial ranking of uncertainties takes place. A selection of 3D simulation models, as defined by the experimental design approach, are run to construct response surface models, which are then used to assess the impact of these uncertainties on field behavior. The historical performance of the field is critical data used to constrain the range of some uncertainties. The results of this study are used to guide future development of the field.The methodology described in this paper highlights the value of a structured multiple realization approach, using experimental design and response surface modeling, for uncertainty estimation and management.
First Deep Horizontal Multi-Lateral Gas Well: Objectives, What We Got, Lessons Learned and Next Steps
Authors: Ginest N. H. , Asiri K. S. , Al-Gouhi W. A. , Haas M. D. , Hembling D. E. , Duncan M. W.
Published: December 2007

Saudi Aramco's first deep Level 3 Plus multi-lateral (ML) gas wells were drilled in the ‘Unayzah sandstone gas reservoirs in the remote Delta (D) Field. This paper describes the processes that were conducted during the initial planning stages by the multidisciplinary development team, the well construction and completion operations, and the post well construction reviews that were conducted to document lessons learned and to make recommendations for process improvements. Extensive detailed planning, a multidisciplinary team approach and solid operations planning and performance led to overall success and paved the way for continued field development with maximum reservoir contact (MRC) well completions.

This paper discusses the development of the reservoir exploitation strategy, the well construction and completion operations, and future well servicing options. The overall strategies included maximizing well deliverability with minimum drawdown, focusing on initial well completion efficiency to minimize formation damage and well intervention requirements, and providing a rigless means to isolate water production from the lower lateral in the future.
Permanent Downhole Pressure Gauges Help Underpin Feasibility of Miscible Gas Flood
Authors: Laws M. S. , Matsuura T. , Soek H. F. , O'Dell P. M. , Kinsella T. J. F.
Published: December 2007

This paper describes a part of the strategy that was developed to demonstrate that a gas flood will be feasible in the Harweel Cluster in Southern Oman.In order to prove this, eight producers and six observation wells were predrilled in four of the reservoirs within the Cluster. During primary production, it was essential to measure downhole pressure data in the observers for a period of up to 2 years.The magnitude and timing of the pressure response at the neighbouring observation wells are indications of the amount of storage (porosity) and the degree of connectivity (permeability) and are therefore key subsurface characteristics.Consequently, permanent downhole pressure gauges were fitted in 11 out of the initial 14 wells (i.e. gauges were also fitted in selected producers as a back up, demonstrating the importance of this information in underpinning the final investment decision to proceed with a gas injection project).The gauges were installed as close to the reservoir as possible to minimise thermal excursion on shut down and start up.A comprehensive analysis of industry wide data was undertaken to determine those vendors capable of providing gauge systems of the required precision and reliability.

In the first field to be evaluated, one of the wells was produced initially while the other three in the field were set up for observation.Pressure drops were observed on all neighbouring wells indicating they were in communication.This data removed one of the major uncertainties impacting gas flood feasibility as it shows that there is no significant degree of reservoir compartmentalisation.Further reservoir characterisation information has been obtained from the magnitude of the pressure response (100-1000 kPa depending on the distance from the producer) and timing (initial response within 1 month).The data from these gauges has clearly helped to underpin the feasibility of a miscible gas flood in this field.
The Fracture Characterization and Fracture Modeling of a Tight Carbonate Reservoir: The Najmah Sargelu of West Kuwait
Authors: Fonta O. , Al-Ajmi H. , Verma N. K. , Matar S. , Divry V. , Al-Qallaf H.
Published: December 2007

This paper presents an innovative and promising, multi-discipline integrated approach that includes geology (BHI, cores, wireline logs), geophysics (seismic facies analysis), and reservoir engineering data (production data, PLT, welltest) that were combined to identify the main types of fractures, to predict their occurrence in the reservoir and to determine the hydraulic properties of the different fractures sets

The Najmah – Sargelu of West Kuwait is an oil bearing reservoir made of tight carbonates where porosity and permeability is mainly provided by the fracture network. In this paper, we will first introduce the method used to identify and predict the two main scales of fractures: joints and large-scale fractures (faults and fracture swarms). The shale content (Vshale) and mechanical beds thickness were found to be the two main geological drivers on joints occurrence. Thickness of individual beds were recorded from BHI acoustic images which enabled to measure an S/T ratio (fracture spacing to bed thickness) for each fracture set and for different shalyness. Secondly, we used an innovative solution to deliver an accurate map of large-scale fractures location. This approach uses concurrently a set of selected fracture relevant attributes in a multi-variable statistical process called Seismic Facies Analysis (SFA).

A 3D stochastic fracture model was then generated incorporating the two scales of fractures and constrained by the reservoir shalyness, the S/T ratio and the seismic facies map. The calibration of the hydraulic properties of the fractures was achieved through the second innovation presented in this paper: the simulation of a synthetic well test using the 3D fracture model and matched with the real data. This resulted in the calibration of the hydraulic fractures conductivity for each fracture type. These values were combined with the 3D stochastic fracture model to produce 3D fracture properties models (porosity, permeabilities and block size) for the Najmah – Sargelu of West Kuwait.
Modeling and Designing Improved Oil Recovery by Steam Injection in Naturally Fractured Reservoirs
Authors: Cicek O.
Published: December 2007

Steam injection in naturally fractured reservoirs provides an extremely challenging problem as well as a potentially effective and efficient improved oil recovery method. Coupling of the two distinct and contrasting matrix and fracture systems results in a highly non-linear problem, and it gets even more complicated as a result of steep changes in fluid properties due to the thermal effects of steam injection. Modeling and designing an optimum steam injection operation in such systems requires an accurate characterization and representation of a naturally fractured reservoir and steam injection operation parameters and dynamics.

In this research effort, a thermal dual-permeability/dual-porosity numerical model is developed for the problem. The multi-phase fully implicit model is three dimensional and compositional, accounting for viscous, capillary and gravitational forces. The model incorporates detailed anisotropic and heterogeneous reservoir property description, and formulates all reservoir and operational parameters as functions of all the primary variables, (2nHC+10), where nHC is the number of hydrocarbon components. The multi-layer production and injection wells are coupled to the reservoir fully implicitly. Both an iterative and a direct solver are employed in the solution of the resulting system of linear equations. The present model is verified and benchmarked against two SPE Projects.

A comprehensive and comparative study is conducted in order to understand the relative effects of naturally fractured system and injection operation properties on the oil recovery performance. This comparative sensitivity analysis is performed using the dual-permeability, the dual-porosity and the approximate conventional single-porosity model.

In search of some practical guidelines, each reservoir system and operational property is studied in a range of naturally fractured reservoirs such as with different matrix block sizes, fracture/matrix permeability ratios and capillary pressures. The present study should help us better understand fluid flow dynamics, design optimum recovery operations and determine range of confidence for an oil recovery operation in naturally fractured reservoirs undergoing steam injection.