bluuebunny/crossref_metadata_2025 huggingface dataset:
A Closer Look at Non-Uniqueness During Dynamic Data Integration into Reservoir
Authors: Cobena Rafael H. , Aprilian Salis S. , Datta-Gupta Akhil
Published: December 2007

Characterizing heterogeneous permeable media using dynamic data such as transient pressure, tracer or multiphase production history typically requires the solution of an inverse problem. It is well known that such inverse problems are ill- posed in general and cannot uniquely constrain the detailed variations in reservoir properties. In this paper, we systematically examine the nature of the objective function during multiphase production data integration to explore the source of the non-uniqueness and the impact of some proposed remedies using prior information, structural analysis or smoothness conditions. The results are compared with ensemble inference from multiple realizations of permeability field generated from dynamic data without using any prior information. We show that continuous nonlinear trade-off between parameters is the major source of non-uniqueness during dynamic data integration. Another source is the presence of isolated, distinct local minima. Our results clearly demonstrate the danger associated with using dynamic data in isolation and the potential pitfall associated with the dictum finer is better'. We show that during reservoir characterization, there is a trade-off between high resolution and minimizing uncertainty and a compromise must be made. Finally, recognizing the general lack of prior information during reservoir characterization, the relative merits of different approaches to remedy the ill-posed behavior are examined.

P. 155
Water Shutoff in Extremely Hostile Environment: An Experimental Approach in
Authors: Krilov Z. , Tomic M. , Mesic I. , Domitrovic D. , Myers R.R.
Published: December 2007

Based on case history and laboratory research, this paper documents the efforts made to date to solve the problem of excess water production in the large gas condensate fields located in the southwestern part of Pannonian Basin Croatia.

According to laboratory studies, a polymer-gel system could be an applicable method to shut off water production in reservoirs characterized as extremely hostile (ultra-high downhole temperature, geologically complex payzone and sour gas, rich with CO). Phenol-formaldehyde crosslinked gels appear to be the most promising for use under such harsh conditions. Long-term stability during in vitro tests, and selective rock permeability reduction during core flooding tests have been achieved at 180C. The problem of retarding the gelation time at reservoir conditions has to be further investigated prior to performing the water shutoff treatment on a candidate gas condensate production well.

P. 225
Control of In-Situ Gelation Time for HPAAM-Chromium Acetate Systems
Authors: Natarajan Dilip , McCool C.S. , Green D.W. , Willhite G.P.
Published: December 2007

Chromium acetate - polyacrylamide gel systems have been used primarily to treat fracture systems, casing leaks and near wellbore regions in matrix rock where short gel times are acceptable. In-depth treatment of matrix rock is limited by gelation time for this system. This paper describes a study of a method to increase gelation time of chromium polyacrylamide systems by using excess acetate ion to reduce the rate of crosslinking between chromium and the polymer. Data are presented to show the effect of excess acetate ions (provided as sodium acetate) on the rate of gelation in bottle tests. Displacement experiments were conducted in sandpacks of various lengths to confirm effects anticipated from bottle tests. Gel samples were prepared at concentrations of 5000 ppm polyacrylamide, 109 ppm chromium acetate and a pH of 5, in sample bottles maintained at 25 C. The effect of excess sodium acetate concentration on the gel times of partially hydrolyzed polyacrylamide-chromium acetate gel systems was determined by varying the mole ratio of acetate to chromium from 3.00 (stoichiometric) to 600. Gelation delays on the order of several days were achieved by increasing the acetate/chromium ratio from 3.00 to 91. Gelation was prevented (for the observation period of one year) when the acetate/Cr ratio was greater than 260. The delay in gelation time was related to a critical acetate/Cr ratio that was characteristic of the concentration and source of the polymer and Cr(III). Aged chromium stock gave significantly shorter gel times than freshly prepared stocks. Displacement experiments were conducted in sandpacks using gel solutions with selected acetate/Cr ratios to determine flow resistance during placement and during brine flow after shut-in. At low ratios of acetate/Cr, buildup of flow resistance in the sandpacks due to formation and filtration of aggregates limited the penetration of the gelant and caused termination of injection. In most of the experiments the time for development of flow resistance was on the order of 10% of the bulk gel times. However, when the acetate/Cr ratio was 600, no buildup of flow resistance was observed when 4 PV of gelant was injected into a one ft sandpack and this system had not gel led in situ at four months after placement. In situ gelation of chromium acetate-polyacrylamide systems at 25 C can be controlled by varying the acetate/Cr ratio.

P. 407
An Artificial Neural Network Model for Estimating Tight Gas Sand Permeability
Authors: Garrouch A. , Smaoui N.H.
Published: December 2007

A back-propagation neural network model has been used to estimate tight gas sand permeability from porosity, mean pore size, and mineralogical data. The optimal network topology consists of an eight-neuron input layer, two five-neuron hidden layers that use nonlinear sigmoid transfer functions, and a linear single-neuron output layer.

The network model has been trained on a data set from a tight gas sand well and tested on some core samples data that were not seen by the network during training. The optimal network architecture was able to estimate back the permeability from the training set within 0.89 % average relative error and was able to predict the permeability of the test data set within 3.3 % average relative error. This is a remarkable result, since linear and nonlinear multivariate regression models were unable to predict the intrinsic permeability within less than 40% average relative error.

P. 25
Parametric Utility Functions for Decisions Under Uncertainty
Authors: Smith Marvin B.
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

By identifying a few key parameters for certain representative algebraic functions which characterize the decision-maker's economic environment, a meaningful utility function can be defined. The specification of these parameters and the appropriate function describe a unique curve relating utility values to potential monetary values. Parametric utility functions offer Parametric utility functions offer solutions to some perplexing problems where expected value theory does not indicate the best decision.

Introduction

Application of utility theory has not been well-accepted as a practical procedure in the analysis of investments procedure in the analysis of investments under uncertainty. Although risk economics in the petroleum industry has evolved to the current state of comprehensive probability models, the incorporation of utility methods has been avoided by most model-builders. Economic analysts generally subscribe to the principle of the expected utility calculation, but the difficulties in obtaining a utility function by the traditional utility experiment have made decision-makers reluctant to introduce such curves into routine problem solving. problem solving. The parametric method for obtaining a utility function presents an alternative to the traditional utility experiment. The purpose of the utility experiment is to describe the decision-maker's intrinsic function, but the parametric approach allows the decision-maker to prescribe the transformation that will be used to compute expected utilities. Parametric utility functions can be defined by group deliberation, while the experimental method is basically an individual effort. A parametric utility function can be updated automatically by changing the values of the parameters, without restudying the philosophical basis for the function.

A PARTIAL LITERATURE REVIEW

The concept of utility was developed by Daniel Bernoulli in his "Exposition of a New Theory on the Measurement of Risk", presented in 1738 to the Imperial Academy of Sciences in Petersburg.
Integrated Workflow Methodologies for Asset Teams
Authors: Tobias Steve , Thompson David , Ahmed Usman
Published: December 2007

Developing oil and gas fields in Southeast Asia profitably can be very challenging. This is partly due to the unique and difficult geological and geophysical problems associated with the Tertiary non-marine basins so prevalent in this part of the world. These problems stem from the discontinuous nature of these reservoirs, which make log correlation difficult and seismic mapping slow and untenable. In addition, reservoirs tend to be highly faulted, and characterized more often than not by poor seismic character. Numerous recompletions, relatively low per-well yields and fast drilling rates combine to pressure asset management teams to continually generate new well locations and update reserves. The workload is immense.

These and other challenges have led to the recent emphasis on workflow planning as a means by which to reduce cycle time and increase integration. Effective workflow demands the need for integrated workstation software system This paper discusses workflow planning in Southeast Asia, its problems, some solutions and implications via the use of the GeoFrame* software platform.
Integration of Production History into Geostatistical Reservoir Description
Authors: Yang An-Ping , Yang Huade
Published: December 2007

Production history is an important reflection of reservoir properties. One of our major goals in reservoir description is to increase production. If we can integrate production data into the building of the reservoir model, we can build a more realistic model and have greater confidence in our predictions. In addition, when reservoir simulation is performed with such a reservoir model, cycle time for history matching can be reduced.

Production data can be applied in reservoir description in three aspects: as soft data in geostatistical gridding, as constraints in gridding, or in post-processing of the reservoir model. The conventional approach of history matching is in the third aspect, which is indirect and time consuming. Our attempt is in the first two aspects. The key is in calculating an attribute from production data that can be calibrated to reservoir properties such as permeability. One such attribute is productivity index. The most difficult task is to normalize the attribute to compensate for differences in starting time, pressure, saturation, mechanical problems, and so on. After verification with synthetic data, the methodology is applied to producing fields with primary production data. The results are consistent with the geological description of the field and can be used in reservoir description. For fields with many wells and lots of data, when the history matching approach is more costly, this approach can be effectively used to map permeability trends and improve the reservoir description model, providing a better tool for optimization of hydrocarbon production.

P. 149
Integrated Reservoir Characterization of Neelam Field
Authors: Joshi Sameer , Lahiri Gopal
Published: December 2007

The Neelam field, located in Western offshore India, is a heteregeneous limestone reservoir of Middle to Late Eocene age with a lack of well defined layering, variation in lithofacies and early high water cut behaviour. Detailed characterization of the reservoir was needed to understand its complex nature in order to arrest the declining production trend.

An integrated reservoir modelling technique was used in order to shorten the E&P interpretation cycle, manage and integrate a large amount of geoscientific data and provide an inbuilt link between the static reservoir model and its dynamic activation using numerical simulation. The available data included well logs, 3D seismic, VSP's, pressure and production data, PVT analyses and core data.

All data was loaded on a common database. Seismic time-depth conversion was done. Well data was tied to seismic and markers correlated across the field. Seismic attributes were mapped and matched with log derived properties. Seismic acoustic impedance was generated. Component thicknesses and properties were mapped across the field with seismic guidance and volumetrics calculated. This resulted in a static reservoir description appropriate to the real life situation. The static description was used in creating a simulation mesh that closely followed the heteregeneities and fault patterns in the field. A complete input data file for a black oil simulator was generated. A consistent reservoir characterization was arrived at which honoured all the input data and successfully explained some of the observed field problems.

Such an integrated reservoir model is an essential building block for an integrated Asset Management system so that the inter-relationship and inter-dependence between different elements in the E&P value chain can be clearly recognized and accounted for.

P. 161
Modeling Simultaneous Oil and Water Flow in Reservoirs with Water Influx
Authors: Permadi A.K. , Mamora D.D. , Lee W.J.
Published: December 2007

This paper presents the development and application of semianalytical solutions to model multi-phase flow of oil and water. Our solutions are modifications of single-phase solutions, with multi-phase flow introduced using the Perrine-Marin "total mobility" to replace single-phase mobility in the standard diffusivity equation. This modification led to very satisfactory agreement between calculated and simulated results. Our results include new solutions for an outer boundary condition of "specified flux." With water influx, this "specified flux" will vary with time and is calculated using an aquifer model coupled with the reservoir model.

The importance of this work is in its possible implementation in software designed for production data and well test data analysis. Most commercial software is limited to single-phase flow, with multi-phase water-oil flow modeled (if at all) by highly simplified models.

Our model assumes a producing well centered in its drainage area surrounded by a cylindrical aquifer or injected water bank. Cumulative water influx is related to the well production and reservoir flow properties by material balance. Any standard water influx model can be used to relate cumulative water influx and the reservoir-aquifer interface pressure.

We relate the average reservoir pressure to well performance using solutions first derived to model single-phase, slightly compressible liquid flow. Oil and water production rates are obtained from the total rate using Darcy's law. Fluid saturations at a given time are computed volumetrically, and this technique does not require knowledge of saturation distribution in the reservoir. Pre- and post-breakthrough oil and water rates are based on fractional flow theory. Although we considered only the case of constant-rate production, our method can be extended readily to the case of constant-pressure production.

P. 263
A New Compositional Simulation Approach to Model Recovery from Volatile Oil Reservoirs
Authors: Syahrial E. , Daltaban T.S.
Published: December 2007

This paper proposes a new compositional simulation approach which has an implicit equation for the oil-phase pressure and water saturation, an explicit equation for the hydrocarbon saturation, and explicit equation for the overall composition of each hydrocarbon component that satisfies thermodynamic equilibrium. The proposed formulation uses an Equation of State for phase equilibrium and property calculations. Interfacial tension effects are included in this research to characterize the thermodynamically dynamic nature of the relative permeability. A two-dimensional relative permeability algorithm is included which handles lumped hydrocarbon phase hydrocarbon phase as well as individual phase flows.

For each grid block two equations are required, namely total hydrocarbon and water-phase flow equations. These equations are highly non-linear and they are linearized by using Newton-Raphson method. The resulting set of equations are solved by an efficient Conjugate Gradient based iterative technique to obtain pressures and saturations simultaneously, and hydrocarbon-phase saturations are deduced from their respective equations.

The new compositional simulation approach is validated through analytical and other numerical methods. lt is demonstrated in this present paper that the results are compared favourably with analytical techniques and published numerical results. They also confirm that the proposed codified formulation is unconditionally stable and it is as stable as the fully compositional model yet the computational cost reduction was substantial.

Impact of sequence-based on correlation style on volatile oil recovery is modelled with this approach. Specifically, the effect of clino-formal permeability barriers on predicted displacement efficiency of oil by injected water and injected gas into volatile oil reservoirs is assessed. The results show that oil recovery factors are strongly affected by the combination of the structure of permeability and the transmissibility barriers between the layers.

P. 281
Improving Flow Simulation Performance with a Seismic-Enhanced Geologic Model
Authors: Hinterlong G.D. , Taylor A.R. , Watts G.P. , Kumar K.H.
Published: December 2007

The DOE Class 2 Demonstration Project operated by OXY USA Inc. in the West Welch Unit was designed to enhance economics in IOR projects in lower quality shallow shelf carbonate reservoirs. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in heterogeneous reservoirs. Therefore, the majority of the pre-injection effort was devoted to developing a geologic model that would allow a flow simulator to accurately match and predict reservoir performance. A base geologic model was constructed utilizing standard correlation and extrapolation methods to distribute the wellbore data across the interwell area. With the base geologic model, the flow simulator could only obtain a history match by making changes in porosity, net pay, and permeability of grid cells in the model. The changes were made using conventional history matching techniques, and the revised geologic model may not have been representative of the formation although a history match was obtained.

The base geologic model was then enhanced by incorporating seismic-guided porosity and pore volume map data to define the interwell properties. Since the seismic traces were on approximately the same spacing as the model grids, reservoir properties of porosity and thickness were available at each grid block. With the enhanced geologic model, the simulator was able to match the historical total fluid rates without the use of porosity or permeability multipliers. The simulator's water/oil ratio was too low with this model. Net pay and pay continuity were identified by other methods as the controlling parameters in the waterflood history match. The revisions resulted in higher oil saturation at the start of CO flood and an increase in forecasted oil production during tertiary recovery than when not using the seismic data. The predicted injection for the first three months is matching the actual field rates indicating these were valid changes to the simulator.

P. 499
The Feasibility Studies of Natural Gas Flooding in Ansai Field
Authors: Zhongchun Liu , Hou Jirui , Zhenhuan Gao , Wu Yanli
Published: December 2007

Ansai field is a typical field with low permeability, low pressure, low production and the water flooding is inefficient. In order to explore an effective developing method for increasing the production and ultimate recovery, we carried out the feasibility studies of natural gas flooding. This paper analyses the feasibility of natural gas flooding from the geological condition of Ansai field at first, then introduces the high pressure slim tube tests for determining MMP of injection gas and reservoir oil and prediction of MMP with published correlation. The high precision correlation has been selected for predicting the composition of injection gas in miscible displacement. The performance of natural gas flooding have been simulated using MVIP simulator. The results shows that Ansai field shares the geologic conditions for natural gas flooding. The MMP of lean gas and Ansai reservoir oil is above 32MPa, and the average reservoir pressure is only 8.81 MPa in Ansai field, so the lean gas flooding is immiscible displacement at Ansai reservoir condition. If accomplishing a miscible displacement at the same condition, the composition of injected gas must be changed by increasing rich gas content, the content is 80%C2H6. The results of numerical computations shows that the recovery ratio of natural gas flooding (26.3%OOIP) is more than of water flooding (20.6%OOIP).Obviously, the natural gas flooding is a hopeful EOR method in Ansai field. These studies provides scientific evidence for the policy of natural gas flooding in Ansai field.

P. 371
Comparison of Well Log and Welltest Data in a Naturally Fractured Formation
Authors: Engler T.W. , Baiar T.
Published: December 2007

Three primarily sources of information available for reservoir description are cores, well logs, and welltest data. In this work, a comparison of formation storage capacity is made between well log and welltest information for a dual porosity, naturally fractured formation. Over the years, two independent parameters, the partitioning coefficient in well logging and the fracture storage coefficient in well testing, have been available to characterize these types of reservoirs. A relationship will be developed between these two parameters.

By definition, well log and welltest data investigate different volumes of the formation; i.e., a variation in scale exists. Therefore, it is likely that when both parameters are within reasonable agreement the fracture storage (Fracture intensity?) is equal within the two test volumes and may be extrapolated as being representative of the given reservoir. However, if the parameters are different, then fracture storage is a function changing with distance from the wellbore.

Application of these principles was tested on a known naturally fractured, sandstone reservoir in the Rocky Mountains. Analysis of this field example resulted in agreement between the two parameters; suggesting a widespread fractured volume. This conclusion confirms the geologic analysis of the area which was described as tectonically active and highly faulted.

P. 51
Enhancing Stimulation Candidate Selection Through Data Integration for 3D Hydraulic Fracture Modeling
Authors: Boonen P. , Byrd A.C. , Frisch G. , Kessler C. , Kubelka G. , Nixon Mark
Published: December 2007

Because of the differences in format and data density, wireline log data are not always used optimally in 3D hydraulic fracture modeling. They do provide, however, the most comprehensive and continuous parameters for borehole stress profile, permeability index, elastic moduli, lithology, porosity and fluid saturation's. A new method is presented to provide all the available logging data in a format suitable for direct input in 3D hydraulic fracture models. An automatic zoning technique divides the data into consistent intervals based on stress contrast. The representative design parameters are then computed for each zone. The outputs are a blocked stress profile and a set of zoned fracture design parameters. This new product provides a synergistic approach to hydraulic fracturing in which wireline logs and rock mechanical analysis are fully utilized together with pump-in tests to optimize the execution and economics of the field development process.

The technique is illustrated by application to a particular South Texas gas field which has suffered severe production decline during the last two years. The object was to identify and treat potential producing zones in all existing wells to increase production. The new log was generated using existing openhole logging data. Based on this log, one well was bypassed for treatment altogether, saving $500,000 to $700,000 on a stimulation that would have had a marginal result at best. In another well, the log was used in combination with a Fluid Efficiency Test/Step Rate test to show essentially no leak-off, and hence, very low permeability in one zone.

P. 107
Development of the Boundary Element Method for A Horizontal Well in Multilayer Reservoir
Authors: Jongkittinarukorn K. , Tiab D.
Published: December 2007

Pressure transient analysis for horizontal wells has gained a lot of attention recently due to the increasing number of horizontal wells. Interpretation of horizontal well test data is much more difficult than for a vertical well. Due to heterogeneity, application of single-layer models fails to interpret the reservoir properties. Numerical methods are essential for a horizontal well in multilayer reservoir with complicated wellbore configuration and boundary conditions.

This paper presents a boundary element method for solving pressure transient behavior of multilayer reservoirs. Two types of boundary conditions, Dirichiet and Neumann, can be handled by the proposed technique. The boundary element method yields several advantages over the conventional finite- different and finite-element methods.

The developed algorithm is successfully applied to some simple cases with known analytical solutions including a finite linear aquifer, a horizontal well in closed reservoir, and a horizontal well in a multilayer reservoir.

P. 317
Multiple Pad-Acid Fracs in a Deep Horizontal Well
Authors: Nelson R.L. , Dyck W.C. , Jamieson F.M. , Jenkins R.A.
Published: December 2007

Panther River is a deep sour gas field situated in the thrust fault region of the Canadian Rocky Mountains operated by Shell Canada Ltd. In 8 years of production, only 3.3% of the 1 TCF of gas in-place has been produced from this low permeability reservoir. A plan was developed to improve the current production by drilling horizontal sidetracks from the existing wells and conducting multiple stimulations along the horizontal length.

Fracture stimulations in this reservoir posed several unique challenges. The reservoir is deep and in a thrust faulted region with expected bottom-hole fracture pressures as high as 130 MPa (18900 psi). This, along with the presence of 2% hydrogen sulfide, created very demanding criteria for the tubing and associated equipment used to isolate the individual fracs. The high pressure and large acid volumes required reliability issues to be overcome in order to utilize conventional frac pumpers. The high rock stresses required deep channels to be etched by the acid to compensate for post frac deformation of the rock. With a radial fracture propagating from a horizontal wellbore, special attention was paid to the interaction of the fracture creating pad fluid and the following acid stage. To our knowledge, it is the first time that the pad fluid was densified with 19% salt in order to match the density of the acid. This paper details these design aspects as well as describing the execution, highlighting the excellent performance of the equipment and frac fluid, along with some of the unexpected challenges that were overcome.

P. 363
Proppant Flowback Control in High Temperature Wells
Authors: James Simon G. , Samuelson Michael L. , Reed Glenn W. , Sullivan Steven C.
Published: December 2007

The control of proppant flowback following fracturing operations can be obtained by several different methods such as resin coated proppant, inorganic fibres or polymer strips. However, each one of the presently available technologies has its limitations, e.g. resin coated proppant cannot generally be used above 190 C (374 F) and requires an activator below about 70 C (158 F), and thermoplastic strips cannot be used above their melting point. Current fibre technology is normally limited to reservoir temperatures below 150 C (302 F), provides only short term control in carbonate reservoirs and cannot be used in situations where the fibres may be exposed to HF. A new high performance fibre for proppant flowback control has been developed to overcome these limitations. Laboratory testing has shown that these fibres are resistant to steam, diesel, xylene, Hcl, and mud acid at temperatures up to 250 C (482 F) for periods up to 7 months. In addition, proppant flowback control measurements at high temperatures have confirmed that the fibres retain excellent proppant flowback control properties. Results of field testing in deep, hot (177 C (350 F) carbonate reservoirs have confirmed the performance of the new fibre.

P. 523
Convection/Encapsulation in Hydraulic Fracturing
Authors: Shah Subhash N. , Asadi Mahmoud
Published: December 2007

New information is presented on the phenomena of proppant convection and encapsulation in the hydraulic fracturing treatments. To fully comprehend this phenomenon, a unique parallel plate flow cell is used which mimics field conditions and is integrated with a fiber optic vision system. The vision system is used to enable the visualization of proppant convection/encapsulation within the fracture. The experimental study involves pulse injection of both 6 and 10 ppg 20/40 mesh sand slurry of 35 lblMgal borate-crosslinked guar into various fluid media under static condition. Data analysis shows that proppant convection/encapsulation is a density/viscosity related mechanism. It is indicated that encapsulation (downward motion of proppant) dominates particle settling in a low viscous medium such as water or linear gel. This phenomena, however, diminishes as viscosity of the lower medium increases. In other words, particle settling within the slurry cluster dominates proppant encapsulation and hence convection. Therefore, it is ascertained that there exists an optimum viscosity value for a given range of density where the influence of density to form encapsulation and convection is inhibited. According to this study, a medium viscosity of 40,000 cp is suffice to sustain a 10 ppg 20/40 mesh sand 35 lblMgal horate-crosslinked slurry and to prevent development of proppant encapsulation/convection.

P. 531
Practical use of Neural networks in Tight Gas Fractured Reservoirs: Application to the San Juan Basin
Authors: Ouenes A. , Zellow A. , Basinski P.M. , Head C.F.
Published: December 2007

An innovative approach that uses neural network technology is developed to identify highly-productive "sweetspots" in the naturally fractured upper Dakota Formation, San Juan Basin, northwest New Mexico. Dakota estimated ultimate recoveries (EUR) are predicted through the vertical and horizontal integration of thirteen reservoir properties taken from three horizons over a 24-township area. The vertical information includes pay thickness, and resistivity (geological facies) from three gross sand units that contribute to the comingled upper Dakota production.

The horizontal information includes, thickness, and resistivity maps for each sand unit as well as structural property maps over the entire 24 townships area. Using a neural network, relationships are established between the thirteen geologic parameters and fracture intensity inferred by the EUR. These geologic models indicate that the parameters that control upper Dakota production are in order of relative importance: thickness, resistivity and structure. The derived relationships are used to predict "sweetspots at locations without well control."

P. 573
Near Critical Gas Condensate Systems: Effects of IFT on Gravity Drainage
Authors: Ceragioli P. , Masserano F.
Published: December 2007

The paper is devoted to show how different estimations of the interfacial tension between oil and gas phases can really affect the overall production evaluations. Obviously such effects are significant only for rich gas condensate reservoirs (liquid drop out >10%).

Commercial reservoir simulators usually calculate interfacial tensions by the parachor method, which is known to underestimate low interfacial tensions between almost equal phases. In fact the parachor method fails just for those values (low values) which are critical.

Besides gradient theory, which is founded on statistical mechanics and therefore completely different from the parachor method, the other procedures are mainly derived from the original parachor method. Such new methods, suitable for calculating low interfacial tensions, can be grouped into two main families: a first group where pure component parachors are modified with respect to the original ones, and a second group where the critical exponent is changed, while parachor values of pure components are just the classical ones. Moreover two kind of mixing rules can be considered for this kind of methods: one founded on the principle of corresponding states and a second one, the Weinaugh-Katz parachors mixing rule.

After a short overview of the methods for the evaluation of the interfacial tension for mixtures and a discussion on the so- called critical exponent, each of them is used for the evaluation of the interfacial tension of mixtures, whose experimental values have been found in literature.

Moreover a real fluid has been taken in account. A synthetic reservoir has been considered and gravity drainages corresponding to the different interfacial tension evaluations, obtained by using the different methods, has then been performed on each of these fluids. All the results are then compared. The comparison shows the importance of the selection of a proper calculation method for the interfacial tension, also to consider a reliable recovery estimation.

P. 169
A Different Approach to Coupling a Reservoir Simulator with a Surface Facilities Model
Authors: Trick M. D.
Published: December 2007

Hepguler, Barua, and Bard1 recently described the integration of a commercial reservoir simulator and a commercial production network simulator using the Parallel Virtual Machine interface2. This paper outlines a somewhat different procedure, based on the same interface, that has been used to couple the same commercial black oil reservoir simulator ECLIPSE3 to a different surface model, namely the gas deliverability forecasting model FORGAS4. For a given case, this new procedure yielded a significant reduction in computation time (a factor of about 30), when compared to the Hepguler et al model, without any loss in accuracy or function. A distinct advantage of this new coupled system is that it is available commercially, unlike the previously described integrated models which were proprietary developments, not available to other companies.
Performing In-situ Stress Tests with Water in Underpressured, Low Stress Zones
Authors: Fairchild Nelson R.
Published: December 2007

With the increased use of 3-D fracture simulators, the need for accurate and affordable formation stress tests has arose. One of the main factors in keeping the test cost down is conducting the stress test with water. In most formations, the stress gradient is high enough (i.e. >0.433 psi/ft) that water can be used, but there are many formations (Berea, Weir, Devonian Shale) that have stress gradients lower than 0.433 psi/ft. When this situation occurs, the hydrostatic pressure of the water can fracture the formation and the well goes on vacuum. This leads to problems establishing constant injection rates and pressures that are usually obtained before monitoring pressure falloff. In the past, formations with low stress gradients used nitrogen for the test fluid, thus keeping the hydrostatic pressure below frac gradient. This method works but is extremely cost prohibited.

This paper explains the problems that can occur when testing low stress gradient formations, and procedures that can be used to gain accurate formation stress profiles using water and a downhole shutoff tool with equalizing ports.

P. 361
Evaluation of Eastern Canada Offshore Gas Potential and Its Impacts on the Market Share in the North American East Coast
Authors: Vikas Shree , Baron Bob , Godec Mike , Ribar David
Published: December 2007

This study provides a comprehensive evaluation of the production, reserves and economic potential of natural gas extraction and transportation from Nova Scotia offshore (Sable Island) plays. Newly available information from Canadian Gas Potential Committee (CGPC) and other private data vendors was integrated into a comprehensive Gas Systems Analysis Model (GSAM), which is a gas supply, demand and transportation model developed by the U.S. Department of Energy (DOE).

Based on the preliminary model runs it has been found that offshore resources in Sable Island have the potential for significant future production. The recovery potential could be greater than the Sable Offshore Energy Project (SOEP) design. SOEP taps only 5 TCF of original gas in place (OGIP) and the total estimate of OGIP could be as high as 18 TCF. Aggresstive advancement of technology and a healthy gas price could warrant a production rate of around 600 mmcfd that is 50% higher than the planned SOEP design. Under such scenario about half the added production will generate incremental demand in the North American East Coast.
Carbon Dioxide Generation in Tugu Barat-C Field and Role in Hydrocarbon Migration
Authors: Prakasa Y. , Hartanto E. , Sulistyo D.
Published: December 2007

Six vertical and directional drillings in Tugu Barat (TGB) field have been proven to be oil and gas production wells. They are infiltrating three hydrocarbon reservoirs, consecutively from the oldest, the Lower Miocene Baturaja Formation, the Middle Miocene Zone 14 and Zone 16 of Upper Cibulakan Formation. Baturaja Formation is composed by limestone intercalated with shale. While the thin Zone 14 and Zone 16 are composed mainly by limestone.

High Carbon Dioxide (CO2) concentration examined in wells results various concentrations without any pattern vertically or horizontally. This gas concentration has been being an interesting phenomenon. Intensive geochemical and petrophysical experiments are needed to predict the sources and process of the CO2 and the effects of CO2 generation in migration and production rates.

Two possibilities have been concluded to be answer of the problem : CO2 is generated from Decarboxylation of coals in the Upper Oligocene-Early Miocene Talangakar Formation or is accounted for by dissolution of the Baturaja carbonate reservoir by formation water, although questioned, has caused in enhancement of CO2 generation.

CO2 generation plays role, although minor, in secondary porosity (fractures). Gas generation, usually causes an over- pressuring inside the formation due to the increasing pore volume. The Decarboxylation is a rapid and ephermal process and can be associated with dissolution of carbonate material.

P. 411
Reservoir Description Techniques Improves Completion Economics in Moxa Arch Frontier Development Project
Authors: Schubarth S. K. , Chabaud R. A
Published: December 2007

The Frontier formation located on the Moxa Arch in southwest Wyoming is a "tight" gas sand that has produced significant gas reserves. Over 700 wells have been drilled and completed in the area covered in this investigation. Hydraulic fracturing is the primary means of completion stimulation and treatments have varied in size and fluid type over the 20 years of development. Many treatment designs and results have been reported in the literature.1,2,3,4,5,6

In designing hydraulic fracture treatments attempts are made to "optimize" the economic return through the use of reservoir and fracturing computer models. The design of the "optimized" treatment and the estimated economics depend on the estimation of many reservoir properties. The most important of these is the estimation of permeability. Most often an average permeability for an area of a field is used. This may lead to a general "optimized" design but not an individual, well specific design. It is only when we can design for specific well conditions that a truly "optimized" treatment design can be achieved.

In this paper we will present a reservoir description technique which has proven successful at predicting the in-situ formation permeability and allowed for intelligent decisions about completion design to be made. Detailed analysis of standard openhole well logs is used to provide this permeability estimation. The ability to predict production response in over 70 wells is the proof that this technique provides valuable information to make completion decisions. We will present the results of these analyses and the production results. We will also quantify the benefit or detriment of different completion designs used in the study area by comparing well response normalized for reservoir quality. The authors believe that the methodology used can be applied to similar reservoirs to achieve similar results.
Critical Gas-Flow Ratio for a Cluster of Wells Over Bottom Water
Authors: van Domselaar H.R.
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Critical gas production rates of interfering wells over bottom water have been calculated for three different well patterns. The calculations are based on the generalized Girinskii potential, which enables one to account for stratification and real gas flow, assuming Darcy's law to hold. This analysis is applicable when the well may be considered as fully perforated.

PVT data are used to establish empirical analytic relationships with respect to pressure. This makes it possible to calculate the generalized Girinskii potential for practical cases. A computer program has been developed which calculates critical rates for clusters of interfering wells in stratified horizontal formations of constant thickness. The program forms an Appendix to this paper.

Introduction

Many gas reservoirs contain bottom water. This imposes a restriction on the gas production from individual wells because above a certain critical rate, which may be different for each well, these wells cut water. The critical rate is defined as the steady-state gas production rate under a drawdown just small enough to prevent water production from bottom water. This critical rate is associated with the phenomenon of upconing bottom water. The form of the steady-state cone depends essentially on the perforation at the well and the reservoir parameters such as stratification.

The majority of the investigations concerned with the determination of critical rates are based on steady-state conditions and segregated flow of the fluids. Many of them, as here, deal with the case of fully perforated wells.

Lehner gives in the introduction to this paper a survey of the work published to date on the steady-state coning problem for compressible flow in stratified layers. The truly three-dimensional problem of free-surface flow in a stratified. problem of free-surface flow in a stratified. formation had already been treated by Girinskii. Girinskii, however, in his considerations applied the so-called 'Dupuit assumptions'.
Waterflooding Of The Olmos-Navarro Sand
Authors: Hester Carl T. , Sutton Gary B.
Published: December 2007

Publication Rights Reserved

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

In South Central Texas, where many fields produce from the tight and shaly Olmos-Navarro sand, waterflooding is gaining momentum after indicated success of pilot operations begun in 1958. Although the nature of the sand and available water present problems, low viscosity oil and favorable water-oil relative permeability relations make waterflooding appear attractive. Currently nine projects are in operation and another is starting soon. Waterflooding in these 10 fields is expected to increase oil recovery by 111 percent of total calculated primary production. It is probable that all significant Olmos-Navarro fields will eventually benefit from this additional recovery technique.

Introduction

There are 45 fields producing from the Olmos-Navarro sand along a trend from Eagle Pass to San Antonio, Texas. (See Figure 1.) The 3439 wells currently producing from these fields average four barrels daily. This low productivity results from prevelant solution gas drive mechanism, reduced reservoir pressures, and the low permeability of the Olmos-Navarro sand. Efforts are under way to increase oil recovery by waterflooding; however, the sand has characteristics objectionable in waterflooding. It is tight, shaly, and highly stratified. Also, available water is undesirable. Regardless of the unfavorable sand conditions and water supply, successful waterflooding in the Olmos-Navarro is probable because of favorable oil-water viscosity ratios and relative permeabilities.

HISTORY OF WATERFLOOD DEVELOPMENTS

Successful waterflooding of the Olmos-Navarro sand was first started in 1958 in pilot operations at Charlotte and Big Foot. As a result, seven other waterflood projects have begun. Also, waterflooding was extended throughout nearly all the Charlotte field, the largest Olmos-Navarro field in the area. Flooding in the North Charlotte field is waiting only on equipment and negotiations between operators.

Table 1 shows waterflood statistics for these fields.