bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhancement of Oil Recovery Using a Low Concentration of Surfactant to Improve Spontaneous and Forced Imbibition in Chalk
Authors: Spinler E. A. , Zornes D. R. , Tobola D. P. , Moradi-Araghi A.
Published: December 2007

A study was undertaken with the objective of evaluating the use of low concentrations of surfactant to improve oil recovery. Various concentrations of commercial surfactants were screened for long term stability at high temperature in seawater. Cloud points, precipitation, and the stability of surface tension were used as screening criteria. Spontaneous imbibition tests at ambient and reservoir temperatures were conducted using reservoir chalk plugs that were moderately water-wet. A selected surfactant, when added at low concentrations (100 to 500 parts per million of active surfactant) to the imbibition water reduced the residual oil saturation over imbibition tests conducted without surfactant. Acceleration of spontaneous imbibition was observed in tests that had improved oil recovery. Forced imbibition tests for viscous displacement were conducted by flow tests. Although low concentrations of surfactant did not lower oil-water interfacial tension below single digits, a reduction in residual oil saturation was obtained in the forced imbibition tests over tests without surfactant. Measurement of surfactant adsorption indicated that low adsorption at reservoir conditions could be obtained below the critical micelle concentration (CMC) of some surfactants. The combination of improved recovery with low adsorption suggests that the addition of surfactant to injected water may improve the economics of surfactant-enhanced waterflooding under appropriate conditions.
Effect of Viscous Forces and Initial Water Saturation on Water Injection in Water-Wet and Mixed-Wet Fractured Porous Media
Authors: Tang Guo-Qing , Firoozabadi Abbas
Published: December 2007

A systematic study of the effect of wettability and initial water saturation on water injection and imbibition was made in Kansas outcrop chalk samples. Water injection tests were conducted at different rates and at different pressure gradients to study the effect of viscous forces. Based on a large number of carefully conducted tests, the following conclusions are drawn.

Initial water saturation has a very pronounced effect on water injection in an intermediate-wet chalk. This effect is much less pronounced for a strongly water-wet chalk. The effects are also in opposite directions. Viscous forces have a very strong effect on water injection performance on intermediate-wet chalks.

Our interpretation of the above experiments lead to the conclusion that the performance of the chalk reservoirs may be nearly independent of wettability state. The results from the experiments also reveal that there is no relation between laboratory measurements of spontaneous imbibition and field performance even when wettability state is perfectly restored in the laboratory.
A New Methodology for Designing Instrumentation of Production Wells for Inflow Profile Estimation
Authors: Nævdal G. , Vefring E. , Berg A. , Mannseth T. , Nordtvedt J. E.
Published: December 2007

A new methodology for designing the instrumentation of production wells is presented. Using a well flow simulator, we can estimate the inflow profile of a production well, solving the inverse problem associated with the mathematical model for fluid flow in the well and the data. The accuracy in the estimated inflow profiles using different design of instrumentation can be computed, and an efficient way of searching for good designs of instrumentation is presented.
Slowing Production Decline and Extending the Economic Life of an Oil Field: New MEOR Technology
Authors: Brown L. R. , Vadie A. A. , Stephens J. O.
Published: December 2007

This paper depicts the results of a forty-five month field demonstration of a microbial permeability profile modification (MPPM) technology to enhance oil recovery from a fluvial dominated deltaic reservoir. Simply stated MPPM involves adding nitrogen- and phosphorus-containing microbial nutrients to the injection water of a conventional waterflooding operation. The resulting microbial growth redirects water flow from the more porous zones to new unswept oil-bearing channels, thereby increasing the efficiency of the waterflood. The success of the technology was shown by the recovery of 69,000 bbl of incremental oil during the first 42 months with a projected recovery of 400,000-600,000 bbl and an extension of the economic life of the field by 60-137 months. Attractive features of the MPPM are that it (1) may be employed in many geological formations amenable to waterflooding, (2) does not interfere with normal waterflooding activities, (3) is environmentally friendly, and (4) is the least expensive of all EOR processes in terms of cost per barrel of incremental oil recovered.
Bacterial Profile Modification With Bulk Dextran Gels Produced by the In-Situ Growth and Metabolism of Leuconostoc Species
Authors: Jenneman G. E. , Lappan R. E. , Webb R. H.
Published: December 2007

Laboratory core floods in highly permeable ceramic and sandstone field cores (1 - 2 μm2) were used to demonstrate the effectiveness of biogenic, bulk dextran gels at reducing indepth permeability. Nutrient formulation, bacteria type, bacteria growth stage, and bacteria concentration were found to influence bulk gel formation.

Growth of Leuconostoc mesenteroides in a sucrose-based medium supplemented with proteins and amino acids essential for its growth resulted in production of rigid, bulk dextran gels containing over 90% water (wt/wt) that were retained on an 18-mesh sieve. Whereas, results from the growth of L. mesenteroides on a beet-molasses medium similar to that used in a previous bacterial profile modification field test produced loose, colloidal gels that easily passed through the 18-mesh sieve. Substitution of inexpensive protein hydrolysates for expensive laboratory-grade proteins resulted in formation of the best bulk gels. Also, bacteria in an early stage of growth produced better bulk gels than bacteria from a later growth stage. Corefloods indicated that conditions supporting formation of bulk dextran gels resulted in greater in-depth permeability reductions (> 90%) than conditions supporting formation of loose, colloidal gels. Batch-wise addition of nutrients (< 5 pore volumes) to ceramic cores inoculated with L. mesenteroides resulted in production of stable in-depth plugs whereas, continuous injection of nutrients was required to achieve in-depth permeability reductions in sandstone field cores flooded to residual oil saturation. These results suggested that the in-depth transport of bacterial cells in field cores was limiting to in-depth gel formation and permeability reduction.

These results are significant in that they are the first to discuss the formation of bulk dextran gels produced during the in-situ growth of Leuconostoc sp., their importance in establishing in-depth permeability reduction, and factors controlling their formation.
Interpretation of Three-Phase Relative Permeability Measurements by Front Tracking
Authors: Haugse Vidar
Published: December 2007

A new algorithm for analysis of laboratory experiments with flow of three phases through a porous medium is presented. The method is based on discrete measurements. Saturation and fractional flow profiles that match the measured recoveries exactly are constructed from measured average fractional flow values. The profiles are piecewise constant in the part of the solution that reaches the outlet during the experiment. The total mobility along the saturation path is estimated from the measured pressure drops. Application to synthetic examples and measured data show that the method is a powerful tool to estimate relative permeabilities along the saturation path of an experiment.
Rheological Screening of Low-Molecular-Weight Polyacrylamide/Chromium(III) Acetate Water Shutoff Gels
Authors: Broseta D. , Marquer O. , Blin N. , Zaitoun A.
Published: December 2007

Low-molecular-weight polyacrylamides crosslinked with chromium(III) acetate are widely used in the oilfield industry to seal off watered out zones in matricial reservoirs. These products are usually mixed in surface facilities, then pumped downhole through coiled tubing and injected into the formation over a depth of several feet. For the operators, gelation time and gel consistency after well shut-in are the two most important parameters to control. The pumping time cannot exceed the gelation time and the maximum pressure drawdown sustainable by the gel is related to gel consistency (as measured, for instance, by the yield stress). Both are known to depend on temperature, polymer concentration and structure (molecular weight, hydrolysis degree), and crosslinker concentration.

A systematic screening of these parameters has been undertaken by means of rheological measurements using a cone-and-plate rheometer. The procedure for determining gelation time consisted in monitoring the viscosity of the polymer and crosslinker solutions mixed at time t=0 and then submitted to shearing at a constant rate. The gelation time, which corresponds to a sudden rise in the viscosity, was observed to be independent of the applied shear rate but to strongly vary with temperature and, to a lesser extent, with polymer hydrolysis degree, concentration and molecular weight and crosslinker concentration. From the set of data obtained, simple correlations or rules of thumb for the gelation time variations are given, which can be used to optimize the formulation for a given field application.

To evaluate gel consistency, some yield stress measurements were performed after a resting (shut-in) time of about 10 hours. The yield stress is related to the maximum drawdown sustainable by the gel in a formation through a simple relationship.
Performance Evaluation of a Mature Miscible Gas Flood at Prudhoe Bay
Authors: McGuire P. L. , Spence A. P. , Redman R. S.
Published: December 2007

This paper summarizes the acquisition, conventional and compositional core analysis, and reservoir simulation history match of a core taken roughly 300 ft from a production well in the most mature area of the Prudhoe Bay Miscible Gas Project (PBMGP). Fine-gridded reservoir simulations yielded a good match of the offset well production rates and also of the observed compositional behavior of the core. The data showed that roughly 70% of the cumulative EOR came from reducing the residual oil saturation near the injection well. The remaining 30% was due to oil swelling. The swelling mechanism was especially important near the production well where the core was taken. Both simulation and field data show that additional miscible gas injection into this area would yield very little incremental EOR.
A Mechanistic Study of Single-Well Steam Assisted Gravity Drainage
Authors: Singhal Ashok K. , Das Swapan , Goldman Jon , Turta Alexandru T.
Published: December 2007

Single Well Steam Assisted Gravity Drainage (SW-SAGD) process was evaluated by closely examining performance of field projects in the public domain, physical modeling and numerical simulation.

It was seen that in order to be economically acceptable, field implementation emphasizes the "Single Well (SW) aspects" (near well bore heating), as opposed to the "SAGD aspects" (creation of a large steam chamber).

The reported steam-oil ratio of about one for SW-SAGD field projects includes contributions due to primary production. Obviously, the performance will be attractive where the primary production is strong. Presence of mobile water or gas in the vicinity of a target location will have a negative effect on performance.

The economic performance can be stronger than that for primary and cyclic steam stimulation but perhaps not as strong as for a dual well steam assisted gravity drainage. Therefore targets should typically have a continuous pay thickness of 10 to 15 m.

Potential improvements can be obtained from optimizing well bore configurations by way of reducing steam by-pass and extending the effective well length utilized for production during the process. Other optimizing ideas involve the use of gases as steam additives and injection-production rate scheduling.

The process is essentially a variation of cyclical steam stimulation (CSS) rather than of SAGD. Using certain elements of the SW-SAGD process, one should be able to profitably modify the cyclic steam stimulation (CSS) process while using horizontal wells.

Introduction

The Single Well Steam Assisted Gravity Drainage (SW-SAGD) process is a steam injection based oil recovery process in which the same horizontal well is used for steam injection, as well as for oil production. Steam is injected through insulated tubing, whereas hot oil and condensed water are pumped to the surface through a separate tubing string. It was initially thought of as a variation of the dual well Steam Assisted Gravity Drainage process (SAGD). In SAGD, steam is injected via a horizontal well and heated oil and condensate produced via another horizontal well, placed directly underneath the injector. The main driving mechanism being gravity.
Integrated Reservoir Description for Boonsville, Texas Field Using 3D Seismic Well and Production Data
Authors: Tanakov M. Y. , Kelkar M.
Published: December 2007

It is generally believed that integration of different types of data can significantly improve reservoir description. To verify this hypothesis, a field case study was conducted on the complex Boonsville reservoir system located in the Fort Worth Basin in North-Central Texas. The zone of interest, Caddo, was interpreted in 3D seismic post-stack data using geophysical means, and different windowed seismic attributes (SA) were extracted around the time horizon. The structure and pay thickness maps were created using both seismic and well data. Correlation between well porosity and SA was established and utilized to generate porosity maps using several geostatistical techniques such as ordinary kriging, kriging with an external drift, and co-kriging. The technique of alternating conditional expectations (ACE) was implemented to maximize the correlation between well porosity and seismic attribute in a transformed space. Integration of this static reservoir model with dynamic (production) data was performed using the flow simulator, ECLIPSE. It was observed that large-scale features played much more important role in matching historical data than small-scale features. Incorporation of seismic data did not significantly improve the history match; however, it may be useful in drilling step-out wells.
Analytical Calculation of Minimum Miscibility Pressure: Comprehensive Testing and Its Application in a Quantitative Analysis of the Effect of Numerical Dispersion for Different Miscibility Development Mechanisms
Authors: Wang Yun , Peck Douglas G.
Published: December 2007

The newly developed analytical approach for calculating Minimum Miscibility Pressure (MMP) is tested using a wide range of slim tube test data involving a number of real crude oil systems. This shows that the analytical method for calculating MMP is capable of determining MMPs that are consistent with slim tube experimental data. The results indicate that this approach not only allows for rapid, accurate and objective determination of MMP for any displacement process, but also makes it possible to determine the displacement mechanisms in a quantitative fashion.

The analytical method is then used to compare with coarse-grid one-dimensional compositional simulation results to investigate the effect of numerical dispersion on the determination of MMP through compositional simulation for different miscibility development mechanisms. Results show that a quantitative description of the miscibility development mechanism as a result of the analytical MMP calculation methodology is a useful indicator of the impact of numerical dispersion on recovery.

It is shown that although for real crude oil systems the displacement mechanism is predominantly the combined condensing/vaporizing gas drive, the effect of numerical dispersion is more pronounced in displacements whose mechanisms are closer to the pure vaporizing gas drive. It is therefore argued in this paper that for detailed compositional analysis of miscible or near miscible gas injection processes, more care must be taken to account for the effect of numerical dispersion if the miscibility development mechanism is close to pure vaporizing gas drive.
Efficient Estimation of the Effects of Wellbore Hydraulics and Reservoir Heterogeneity on the Productivity of Non-Conventional Wells
Authors: Wolfsteiner Christian , Durlofsky Louis J. , Aziz Khalid
Published: December 2007

An efficient semi-analytical solution method appropriate for the approximate modeling of the performance of non-conventional wells operating under primary production is described. The approach, referred to as the s-k* method, accounts approximately for the effects of reservoir heterogeneity and for pressure losses within the wellbore. The accuracy of the method is demonstrated through comparison to detailed finite difference results. Extensive calculations for the performance of non-conventional wells in multiple realizations of log-normally distributed permeability fields are then presented. The effect of wellbore hydraulics on well performance is assessed for several different well geometries and for varying degrees of reservoir heterogeneity. Comparisons between ensemble-averaged quantities (i.e., results averaged over many realizations) and results for a single "average" (homogeneous) reservoir representation are also made. As expected, these calculations differ in general, though for some quantities (e.g., productivity ratio) the homogeneous results give very accurate estimates. The overall approach provides an efficient means for estimating the combined effects of reservoir heterogeneity and wellbore pressure losses on the productivity of non-conventional wells.
Practical Application of Fractal Model to Analysis Interference Test in the Naturally Fracture Reservoir, Amoseas Indonesia Inc.
Authors: Kristanto D. , Abdassah D. , Siregar S.
Published: December 2007

The use of fractal model in Pressure Transient Test Analysis was introduced by Chang and Yortsos in 1990. Their concept was derived from the assumption of Warren and Root model where their reservoir contains two systems with contrast in porosity and pemeability properties, which are well-known as matrices and fracture network.

The fracture network is assumed to be connected and distributed as fractal object in a homogeneous medium (matrix) of Euclidean Geometry. Fluid flow from reservoir to well occurs only through the perfectly connected fracture network. Based on these assumptions, Chang and Yortsos developed the unsteady-state flow of slightly compressible fluid and proposed an extension of the diffusivity equation to model transient flow in fractured reservoirs, especially in single well testing.

The physical and mathematical model descriptions are developed from Chang and Yortsos model. By Type Curve Matching technique, we can analyze the interference test in reservoir considered as a complex naturally fractured reservoir such as the one operated by Amoseas Indonesia Inc. Besides transmissibility and storativity we can also obtain the fractal dimension which can be used to predict the complexity of the reservoir.
Structural Evaluation of Petroleum Sealing Capacity of Faults
Authors: Sorkhabi R. , Suzuki U. , Sato D.
Published: December 2007

Japan National Oil Corporation is conducting a five-year project on the Evaluation of Traps and Seals. As part of this Project we have designed a conceptual model for evaluating faults as petroleum conduits or barriers in sedimentary basins. This structural evaluation draws on several geological databases from the North Sea, UK, Niger Delta, Utah, Texas, Gulf of Mexico, Trinidad, Persian Gulf, and Indonesia. Our model integrates various parameters affecting the flow properties of faults into tectonic setting and fault style, fault geometry, fault damage zone, fault rock in contrast to host rock characteristics, and fault chronology and time-scale (geological, production and seismic time scales). We distinguish between "fault traps" (due to juxtaposition of shale against sandstone layers) and "sealing faults" (in which mechanical and chemical changes along the fault plane produces a barrier to petroleum flow. Allan-type juxtaposition diagrams (fault-plane section analysis) are useful tools to evaluate fault traps but not sealing faults. Major processes of sealing faults include fault compaction and cataclasis, cementation due to fluid channeling along the fault, and clay smearing. Data on fault rocks and their corresponding undeformed host rocks show that faulting processes can reduce the rock permeability by two orders of magnitude. Quantitative a approaches for assessment of clay-smearing include Clay Smear Potential (CSP), Shale Smear Factor (SSF), and Shale Gouge Ratio (SGR). All these parameters depend on the thickness of faulted shale layer and fault throw. The available data indicate that CSP of >15, SSF of <7, and SGR of >18% are threshold values for fault sealing in normal faults. While across-fault direction may be a membrane seal for petroleum flow, the fault damage zone may actually increase the permeability for the flow along and in the vicinity of the fault if the open fractures are not healed by mineralization and collapse. Analysis of fracture density, aperture, orientation, and connectivity, as well as fault-zone diagenesis are therefore important in fault-sealing evaluation. Our conceptual model is helpful in exploration because faults commonly occur in sedimentary basins and such a model provides a tool to rank a population of fault-bound prospects based on their relative and probable fault sealing capacity.
Geological Modelling of a Heterogeneous Volcanic Reservoir by the Petrological Method
Authors: Kawamoto Tomohisa , Sato Kozo
Published: December 2007

In dealing with heterogeneous thick formations, objectivity of well-to-well correlation is often hard to maintain and this is the case for a volcanic formation, the Minami-Nagaoka gas field. To overcome this difficulty, the refractive index is utilized to identify the different types of plagioclase, with which the well-to-well correlation is established in an objective manner and the formation is divided into six volcanic bodies.

One of the identified bodies corresponds to the productive zone encountered in the southern region of the field. This volcanic body is glassy rhyolite and extensively distributed throughout the field, even toward the northern region, where the productivity is poor. To explain the regional difference in productivity, various types of alterations are examined, including devitrification, montmorillonitization, chloritization, illitization, and albit ization.

Identifying the primary volcanic bodies and examining the secondary alterations enables us to construct a geological model of the subject volcanic formation. Integrated geological interpretation yields a clear view of the formation and a reasonable explanation to the productivity aspects.
Use of a New Reservoir Model in Pressure Transient Analysis Reduced Uncertainties in Asset Appraisal
Authors: Guo Boyun , Toro Mario
Published: December 2007

Asset appraisal using pressure transient data relies on match between actual reservoir pressure response and analytical models. However, it has been found that existing analytical models are not adequate for complex reservoirs detected by modern pressure gauges. Therefore there exist high uncertainties in asset appraisal based on welltest analysis in these reservoirs. It is highly desirable to develop realistic mathematical models describing the behaviour of complex reservoirs for asset appraisal.

This paper demonstrates applications of a new mathematical mode to evaluations of two complex oil reservoirs. The flow regime in the first reservoir during test was identified by the new model as linearly supported radial flow (LSRF). The new model provided a significant improvement in matching pressure transient data and data interpretations. The interpretation results were verified using a numerical welltest simulator.
Integration of Subsurface Disciplines to Optimise the Development of the Mardie Greensand at Thevenard Island, Western Australia
Authors: Tippet P. J. , Beacher G. J.
Published: December 2007

The history of the development of the Mardie Greensand reservoir at Thevenard Island illustrates the successful integration of subsurface modelling disciplines to enable the development and optimisation of a previously discarded hydrocarbon bearing zone. This has added 20-30 MMstb of Proved Reserves to the Thevenard Island asset. In particular, the use of G2-GOCAD modelling to generate a geostatistically populated grid proved invaluable in incorporating the heterogeneity of the reservoir. Formation evaluation modelling work contributed to the understanding of the reservoir petrophysics and better hydrocarbon identification from logs. Seismic EDGE (Enhancement & Detection of Geological Events) processing allowed the stratigraphic boundaries of the reservoir to be more accurately defined. Other seismic analyses have suggested that a northern extension to the field exists. The Chevron proprietary reservoir simulator, CHEARS, was used to model the reservoir and has also provided evidence for a northern extension to the field. The model has also been used to assess the value of infill well locations, and most importantly, the potential value of secondary recovery mechanisms such as water or gas injection. Finally, horizontal drilling technology and innovative geosteering techniques have contributed to the successful drilling of a number of horizontal, sinusoidal producing oil wells. Recently, the Mardie Greensand reservoir at the nearby Cowle oilfield was exploited as a result of an integrated effort using the knowledge gained at Saladin.
Rigorous Inclusion of Faults and Fractures in 3-D Simulation
Authors: Phelps Robert E. , Pham Tony , Shahri Ali M.
Published: December 2007

Integration of well test results, horizontal well information, bore hole imaging, see Figure 1, 3-D seismic, and coherency analyses has made possible the ability to locate and define vertical faults and fractures. Fracture orientation, Figure 2, based on image log data from several wells, can increase our understanding of how the direction of these fractures effects reservoir performance. Conductive faults and fractures that contribute to fluid flow, along with stratified high permeability regions, must be included in our mathematical models.

Capturing the correct physics of fluid movement improve these reservoir simulation models accuracy as predictive tools.

To illustrate this point a sector model of the Beta reservoir was constructed using several different LGR (Local Grid Refinement) regions each represented a vertical fault and fracture system. These vertical fault-fracture systems, as depicted in Figure 3, were combined with high permeability stratified layers to construct a reservoir simulation model. This model was used to study possible inclusion of vertical faults and fractures, and investigate their effect on reservoir performance.
Integrated Reservoir Geomechanics Techniques in the Burgos Basin México: An Improved Gas Reservoirs Management
Authors: Berumen Sergio , Cipolla Craig , Finkbeiner Thomas , Wolhart Steve , Rodríguez Fernando
Published: December 2007

An overall geomechanical model was developed in the Wilcox sands of the Arcabuz-Culebra field, a tight gas reservoir in the Burgos Basin, northern México. The application of multiple technologies were integrated to build a geomechanical model of the field, which was used as a primary tool to predict fracture direction and stress field distribution. Advanced fracture diagnostic technologies that measure the created fracture geometry were used to support the geomechanical modelling.

The technical approach combined geomechanical modelling, hydraulic fracture mapping, fracture and reservoir engineering studies to optimise fracture treatment designs and improve the planning of well location and spacing. This methodology can be very important to avoid drilling unnecesary wells or leaving gas in place.

By integrating geomechanics techniques through single well reservoir modelling it was observed that ineffective well positioning could inhibit production by as much as 0.5 BCF per well. Fracture engineering analysis identified significant potential cost savings by reducing fracture treatment size and changing proppant type. In addition potential production increase of 3 BCF per well may be possible with re-fracture treatments. This paper discusses these results, and presents a case history that details the application and integration of reservoir geomechanics technologies to improve the practices in the gas reservoir management.
Reservoir Management Strategies For Development of Gas Dissolved In Water (Brine) Reservoirs
Authors: Manrique J. F. , Kaneko T.
Published: December 2007

Reservoir dynamics and the unique physics of the production behavior for this type of reservoirs make it an interesting reservoir enhancement problem. The potential of different well completions can increase significantly the existed production levels and the economic objectives as compared to current completions practices, which makes this a unique production engineering challenge.

Gas dissolved in water (GDW) reservoirs, are a unique application of reservoir and production engineering. However, development and optimization of this type of reservoir can be easily implemented by application of current technology. A workflow process for reservoir management of this type of reservoirs is introduced. An integrated approach was taken to properly characterize a typical GDW multi-layered reservoir.

Past performance was used to quantify potential. A reservoir simulation approach was developed to match and validate reservoir performance and to forecast production from alternative completions. Although the suggested alternate completions are relatively common and easy to implement, their application to this type of reservoirs is unique and innovative.

Economic evaluation was performed to determine feasibility of the alternative completions. Montecarlo simulations were used to evaluate and quantify financial risk and applied engineering for development of field best practices. Findings and results are encouraging and suggested strategies that may result in increased production and sustained economic return.
Application of the Method of Experimental Design to Quantify Uncertainty in Production Profiles
Authors: Venkataraman R.
Published: December 2007

Quantification of uncertainty in reservoir performance is an important part of proper economic evaluation. The uncertainty in our understanding of a given reservoir's performance (e.g. reserves at the economic limit) arises from the uncertainty in the information we have about the variables that control reservoir performance (e.g. permeability, oil water contact, etc.). The problem is complex since the influence of the variables on the reservoir performance is often non-linear. Conventional techniques often ignore this.

This paper describes the application of the method of Experimental Design to this problem. It consists of the following five steps :- (i) Identify the ranges of the important variables that influence the recovery, (ii) Experimental Design to identify the values of the variables at which the recovery is forecast, (iii) "Conduct the experiments" - use reservoir simulation to identify the recovery for each of the experiments identified in step (ii), (iv) Analyse "the results of the experiments" and establish a generalised multivariate correlation of the recovery as a function of the variables, (v) Validate the correlation arrived at in step (iv), and (vi) Predict the distribution of the uncertainty in the recovery. Here the term ‘recovery’ is used in a generic sense; the technique can be employed to any parameter of interest e.g. gas flow rate after ten years of production. The paper discusses an example of the application of the Composite Design to a North Sea gas field.

This technique has potential value in providing input to evaluation of economic risks in a project in the appraisal and development stages.
Early Water Breakthrough – X-ray CT Visualizes How It Happens in Oil-Wet Cores
Authors: Oshita Toshiya , Okabe Hiroshi , Namba Takao
Published: December 2007

In-situ saturation monitoring during a coreflood with X-ray CT scanner confirmed that the waterflood performance of a mixed-wet core is totally different from that of a water-wet core. Namely, it was observed that the brine injected in the mixed-wet core preferentially invaded into the most porous lamina, causing early water breakthrough at an outlet end. This result gives a significant insight into understanding the mechanism of unexpected early water production that has frequently been reported from some giant carbonate reservoirs in the Middle East. Many efforts have been made to grasp how such phenomenon took place. One of the most widely accepted explanations at present ascribes it to reservoir heterogeneities such as the existence of super permeability streaks. A drawback of this super-k concept is, however, that neither cores nor conventional logs could detect their locations. Thus, based upon the experimental result above, this study aims at associating the localized wettability conditions of the core sample with the early water breakthrough. For this purpose, a numerical study was carried out, using 3-D images of the in-situ saturation distribution obtained from X-ray CT scanning. Then, the waterflood performance of the mixed-wet core was successfully reproduced in the computer model. It was concluded from this numerical study that in spite of the small variation in porosity and permeability, the local variation in wettability can occur within the Berea sandstone core after it has been in contact with crude oil. As a result, the brine is preferentially imbibed in and runs through the more water-wet laminae, causing the finger-shaped water encroachment and, finally, the early water breakthrough.
Tilted oil water contact in the Cretaceous Caballos Formation, Puerto Colon Field, Putumayo Basin, Colombia
Authors: Carlos Estrada , Cesar Mantilla
Published: December 2007

After three attempts in the last 6 years to fully characterize the reservoir in the Caballos Formation in the Puerto Colon Field, different approaches to explain the reservoir heterogeneity have been suggested, each of which involves a great deal of uncertainty. Of particular importance is the fact that the oil-water contact has been found at varying depths from well to well. This variation could not be satisfactorily explained structurally nor stratigraphically. Bouttete et al, 1993, on the basis of incomplete 2D seismic information integrated to an extensive set of geologic and engineering data stated that there are three different reservoirs in the Caballos Formation. In 1996, Calderon et al, using additional well and seismic data, concluded that there is a single tilted oil water contact in the Formation. There is strong evidence supporting each of these models but there are still some inconsistencies. Recently, Peña et al, performed a thorough structural, stratigraphic and petrophysical review. This latest approach considered improved data management procedures and geostatistical modelling in order to produce a better picture of the reservoir. A rigorous validation and integration process under a project database allowed the workteam to improve the understanding of the system under study. By combining geostatistical modeling with geologic expertise it was possible to reduce much of the uncertainty and choose the most probable static and dynamic models of the reservoir. It was found that there are not sufficient elements in the static and dynamic models to account for the existence of three different reservoirs. A tilted OWC was accepted as the best representation of the reservoir for the available information.
Rejuvenation of the Aging Fairley Baram Unitized Field
Authors: Yusoff Shahbehri , Salleh Alias , Kamari Yusoff Mohd
Published: December 2007

Fairley Baram Unitized Field straddles the border of Brunei and Sarawak, Malaysia and is among the identified marginal fields that contain far greater HIIP than previous estimation. Realizing the upside potential, both joint operators, Petronas Carigali Sdn. Bhd. (PCSB) and Brunei Shell Petroleum (BSP) formed a team to review and plan for the field further development and appraisal activities.

The development phase of the campaign proved greater oil columns in proven reservoirs and developed 5.2 MMstb of oil reserves. The appraisal phase proved that the incised valley is predominantly shale filled with sand body at the base. The shale interval provides a seal and separation for reservoirs abutting to it. Deeper sands underlying the developed reservoirs were also proven to be hydrocarbon bearing. A revised volumetric incorporating the new data from the campaign indicates that the HIIP is substantially bigger than the pre-review volumes.

The re-processed 2D seismic, petrophysical, production and well data were fully utilized in the study. The deliverables are re-interpreted structural maps, in addition to the newly formulated depositional concept and revised petrophysical input. The depositional model is interpreted as an incised valley with slumping due to the tectonic movement or fall in sea level.

This paper discussed how the integrated field review enabled the team to better understand the field performance and better managed the uncertainties. The integrated field review also demonstrated that it is possible to turn around a ‘brown’ field and improved the field production rate by identifying additional proved develop reserves and at the same time replenish reserves from the appraisal targets.
The Role of the Local Petroleum Service Company in Asset Management
Authors: Barwani M. , Marhubi A. , Oligney R. E. , Economides M. J.
Published: December 2007

Petroleum production grows from frontier to semi-mature to mature. There have been several attempts to quantify a petroleum region's production profile, including seminal works by Hubbert and others. Both the physics of production and the economics of exploitation are presumed to influence this profile. Defying the log-normal distribution which was suggested by Hubbert, entire petroleum provinces have extended their production history into a much flatter and considerably wider profile, recently characterized as fractal. Maturity implies, among other characteristics, small pool exploration, commoditized drilling and, especially, production enhancement services. We suggest that the transition in the production profile is characterized and at the same time aided by the flight of the major service company (which has become even bigger and more diversified) and its replacement by smaller service companies. There are significant distinctions between the local and international service companies. These include issues such as local vs. global knowledge, non-integrated vs. integrated services and a low vs. high comfort level by the clients. The mix of the local service companies can be greatly affected by the local operators. It must be emphasized that the quality and spectrum of services are crucial elements for the survival of the local petroleum production. We present here a model for the local service company/operator interaction, the changing role of the major service companies and criteria for technology utilization and required proficiency. We apply these concepts to a highly mature area (Oklahoma) and to Oman, entering maturity now.
Single Well Reservoir Management - the Ultimate Multibranch Well Challenge
Authors: Ehlig-Economides C. A. , Economides M. J.
Published: December 2007

Whether due to the lure of deep-water prospects or the shear excitement to apply new technology, the recently developed multibranch wells are likely to play a crucial role in the future of petroleum exploitation. The challenge is to adjust and even develop reservoir management strategies both suited to and taking advantage of this technology. In effect, a multibranch well provides an underground gathering system. When the design includes downhole separation that provides for the production at the surface of desired fluids with reinjection of unwanted ones, the well incorporates an underground production facility. To achieve these sorts of objectives, the entire system of branches, completions, manifolds, separators, etc., must be in place and operational before the well can begin to produce. The design considerations that would enable this result rely on a modular approach to the problem and provision for contingencies for uncertainties in the reservoir description and in the reliability of the underground system. This paper outlines the issues that must be considered and provides a framework for the well design process.
Optimizing Simulation Models by Upscaling from Integrated Reservoirs Models: A Case History
Authors: Ali Zaki A. , Al-Qassab Hisham M.
Published: December 2007

This paper presents a case study of using integrated models in improving upscale accuracy that increases the model speed. This has a great impact on CPU time and therefore the cost of the study. A unique process that integrates data from all possible sources (open hole logs, RFT and production data, seismic and geologic interpretations) was used in a geologic model. This static geologic model was then used to build a DYNAMIC simulation model. We superimposed water encroachment movement over the geologic model that in turn was recycled back in developing the simulation (engineering) model. Up-scaling the resultant model was done using a multi step technique that captured all the varying details of the complex reservoir such as:

a) A tilt in the free water level coupled with the effect of capillary forces on reservoir fluid distribution; b) Reservoir stratification which has the effect of limiting bottom water support and causing the injected water to move rapidly through the high permeability layers; c) While the effects of stratification and faulting are apparent, communication is observed across these features.The study was done on a sector model extracted from the full field geological model as a pilot testing of the method. The same procedure was then applied to the full field model. As a result of using this technique, pressure and water saturation match was obtained and prediction cases were submitted to predict reservoir performance for designing operational and production strategies for the field.
History Match of the Complex Carbonate Neelam Field
Authors: Carnegie A , Joshi S , Lahiri G
Published: December 2007

Neelam is a heterogeneous carbonate oil field, located offshore India. In addition to aquifer and gas drives, pressure is maintained by water injection. Production is from vertical, deviated and horizontal wells. Severe, unexpected production problems, such as high water cuts and low oil rates, have been encountered. To address these, a multi-disciplinary reservoir study was performed, which integrated available data, and has created a history matched flow simulation model of the field. This model will aid development of strategies to optimise the oil recovery from the field. The characterisation of the field to prepare it for flow simulation was described in another SPE paper (1). There it was shown how diverse types of information, for example well logs and acoustic impedance's derived from seismic data, were integrated using advanced techniques and software to efficiently create an input model for flow simulation. This paper describes the history matching of that model with a fluid flow simulator. It will show that for much of the field, the model actually did not require much modification, thereby validating the approach described in the previous paper. This is noteworthy, given that flow properties of carbonate fields (including Neelam) can be potentially very difficult to capture. However, as will be described, during the history match the model did need development in certain crucial areas. Notably, the areal compartmentalization of the field into separate flow blocks after a major material balance study, and the implementation of high permeability streaks, which were inferred from dynamic data (production logs, production rates and pressures, RFT's). It will be explained that the identification and parametrisation of such streaks was aided by a simple probabilistic technique implemented in an interactive PC package developed by the team during the project. Finally, descriptions will be provided of the strategies, which were developed to efficiently achieve a realistic history match in spite of the difficult nature of the problem. These strategies will be used to suggest some general recommendations on workflow and procedures in integrated reservoir studies.
The Application of Probabilistic and Qualitative Methods to Asset Management Decision Making
Authors: Simpson G. S. , Lamb F. E. , Finch J. H. , Dinnie N. C.
Published: December 2007

Interviews have been conducted with decision-makers in most of the operating companies active in the UK North Sea. The data generated by these interviews defines industry current capability in decision analysis. The extent to which each company uses the techniques which comprise current capability defines a rank list representing relative level of sophistication in decision analysis. This rank list is then correlated with other rank lists based on common measures of business performance to establish the value, to companies, of adopting best (or, at least, better) practice in decision analysis. The strong positive correlation found indicates a considerable incentive for companies to upgrade their decision analysis capability.
Asset Optimization Using Multiple Realizations and Streamline Simulation
Authors: Pallister I. C. , Ponting D. K.
Published: December 2007

Reservoir simulation results may be presented in terms of asset net present value. This may be used to make decisions regarding alternative production strategies or in-fill drilling programs based upon economic criteria. If the simulation and value assessment is performed for a number of possible realizations of the reservoir geological model an estimate is also obtained of the risk involved in each production decision made. Ideally, optimal strategies for all realizations should be compared, rather than one tuned to a single possibility.

Such a system implies a fast reservoir flow simulation engine. One possibility is to use a streamline solver. These yield simulation results quickly, but introduce significant approximations in the treatment of gravity and viscosity changes. An alternative is to use a fast finite difference or finite element simulator. We compare the results obtained using these methods, in economic terms as well as in terms of production profiles.
Full Field Model Study of a Dense Highly Fractured Carbonate Reservoir
Authors: Fathi A. , Ansari A.
Published: December 2007

The purpose of this paper is to present the results of a comprehensive subsurface study of a field in South of Iran. The reservoir is typical of several carbonate fields in south west Iran, comprising low porosity carbonate, but highly fractured. After several years of natural depletion a gas injection was started at a time that reservoir became saturated at the crest to prevent further shrinkage of the oil and keep the reservoir oil pressure constant. The source of gas was a deeper reservoir where the gas was produced and injected by its own pressure through one producer and one injector.

A three dimensional model was set up using a 3D static model as the basis for geological input. All available data including, fluid losses during drilling, well test and flowmeter surveys were used to define the fracture properties. A good history match was obtained for pressure and fluid levels with a commercial black oil simulator using the model in dual porosity mode. The calibrated model was then used in prediction mode to forecast the reservoir behavior under gas injection pressure maintenance and also repressuring close to original crestal pressure. The simulation results show large increase in ultimate recovery due to gas injection as compared with natural depletion.