bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of Engineering Data and Geostatistics in Simulation of a Complex Carbonate Reservoir
Authors: Liu J. S. , Enwall R. E. , Davis R. R. , Douglas J. L. , Barber R. M.
Published: December 2007

Complicated geology and scarce data are the two major problems in simulation of the subject large carbonate reservoir. Sharp contrasts in permeabilities, ranging from tens to more than one million milli-darcy-feet, are observed in a few hundred meters radius of the reservoir. Field data and past experience in reservoir simulation indicate that the field performance is completely dominated by these super high permeability streaks. Recent studies have shown that these high permeability streaks are very localized. The occurrence of these streaks is random and not correlatable. Consequently, they may be only amenable to geostatistical techniques. The Indicator Conditioned Estimation (ICE) technique described in this paper is designed to honor the spatial structure inherent in the source data and to allow for the prediction of super permeability streaks in areas of no well data.

The use of pulsed neutron capture logging and production logging has been very successful in monitoring the sweep of the subject reservoir which is under a peripheral waterflood. At the same time, the logging data has also provided a wealth of information for the model construction; however, only the data derived from dry wells has been used in the past. A new procedure is developed to use information from wet as well as dry wells to augment the database for the model construction. This procedure in conjunction with ICE technique has formed an innovative way to generate the initial permeability distributions for a simulation model. It is expected that this initial permeability distribution should serve as a better starting point for the subsequent history matching process.
A New Reservoir Simulation System for a Better Reservoir Management
Authors: Lefevre Didier , Pellissier Gérard , Sabathier J-C.
Published: December 2007

Practically all the problems of reservoir development or reservoir management are analysed with a reservoir simulator. This tool must, consequently, be very versatile to allow to test very different hypothesis and very user friendly not to waste the engineer time. Indeed reliability, accuracy, performances are some of the basic requirements for an industrial tool.

Many simulators are presently available on the market. However, their range of applications is often limited and different "versions" have to be used to solve different problems. Differences between the versions (mainly due to different updatings and different programmings) may be detrimental to a sound appreciation of the discrepancies between two predictions made with two different versions. Consequently it was decided to create a new reservoir simulation system covering a very large range of possible applications and having a structure opened for new implementations. A key point is that, from the user's point of view, the model must not be more complex than required by the problem as far as input, documentation, memory requirements and performances are concerned. This is possible through a very efficient software management which is described in another paper[1]. Here we only describe some specific features of the general structure of the system, and of the geometry and well modelling aspects.
The Role of Simulators in Reservoir Management
Authors: Satter Abdus , Brugman R. J. , Yard M. B. , Mims D. S.
Published: December 2007

A reservoir’s life begins with exploration leading to discovery followed by delineation of the reservoir, development of the field, production, and finally to abandonment. Sound reservoir management is the key to successful operation of the reservoir throughout its entire life. The modern reservoir management process involves setting a goal and developing a plan, implementing and monitoring the plan, and evaluating the results.

Reservoir simulators play a key role in providing production and reserves forecasts needed in developing a reservoir management plan, monitoring, evaluating, and operating the reservoir. As opposed to only one reservoir life, the simulators can simulate many lives for the reservoir under different scenarios, and thus provide a very powerful tool to optimize reservoir operations.

This paper will discuss briefly reservoir management methodology and illustrate the role simulators can play in reservoir management with the following examples: Newly discovered offshore oil field: A black oil simulator was used to determine optimum recovery scheme, i.e., natural depletion or natural depletion augmented by water injection, and well spacing requiring the number of wells and platforms, reserves and economics. The simulation results were used to develop the optimum economic reservoir management program including development plan, and requirements to implement the plan, and to monitor and evaluate the project performance.Thermal recovery project: A thermal simulator was used to history match cyclic injection into a heavy oil reservoir. Based on the simulation study, wellbore damage and completion technique were identified as the cause for poor production response. A new well with an open hole gravel pack completion produced at a favorable rate.CO2 recovery project: A compositional simulator was used to history match performance of a primary depleted oil field followed by its performance prediction under CO2 flood. This study was made to optimize injection/production scheme including timing of blowdown and level of operating pressure.
Geochemical Study of Tar in the Uthmaniyah Reservoir
Authors: Tobey M. H. , Halpern H. I. , Cole G. A. , Lynn J. D. , Al-Dubaisi J. M. , Sese P. C.
Published: December 2007

Tar is believed to be the main factor impeding production in certain regions of the Uthmaniyah area, Ghawar field. The effect of extraction with several solvents on the permeability and porosity of core plugs from tar zones in the Arab-D Formation was determined in order to understand to what extent tars contribute to obstructing the rock pores. Thin section examinations of the extracted rock were conducted to discern where the tar was distributed microscopically and how that distribution corresponded with the permeability and porosity data. The data show that in general, while organic matter continued to be removed by increasingly polar solvents, the effective permeability, which is controlled by the macropore system, showed little improvement. While the major pore network and macroporosity can generally be improved in the initial extraction, the marginally accessible porosity is still largely occluded by tar. Elemental and pyrolytic analyses of core samples before and after extraction indicate that the tar is neither itself homogeneous, nor uniformly distributed through an individual well, or from well to well. Some components of the tars are not soluble to any of the organic solvent systems utilized, and evidence that some of the tar may result from thermochemical sulfate reduction (TSR) is presented.
A Reservoir Characterization of a Naturally Fractured Reservoir: The Point Arguello Field, Offshore California
Authors: Buchwalter J. L. , Anderson D. M. , van Bloemen Waanders Bart , Genovese Paul
Published: December 2007

A method has been developed to significantly improve the confidence in matrix block size and permeability determination fornumerical modeling of naturally fractured reservoirs.

The concept of fault bend folding from structure geology technology was used to divide the reservoir into areas of similar strain history, and hence fracture intensity. This technique was integrated with thewell test and conventional core data to obtain values for matrix permeability and block geometries areally acrossthe reservoirand vertically on a mechanical unit basis.
Numerical Simulation of Naturally Fractured Reservoirs
Authors: Fung L. S- K.
Published: December 2007

The use of the dual-porosity approach for the modeling of naturally fractured reservoirs has become widely accepted in the oil industry. In this approach, it is assumed that the fissured porous media can be represented by two collocated continua called the matrix and the fracture. The original idealized model assumes that the fracture is the primary conduit for flow whereas the matrix acts as distributed sources and sinks. Since the introduction of this idealized model into the petroleum literature some 30 years ago, several improvements and/or refinements have been proposed. For example, the dual-permeability model was introduced when it became evident that for some fractured reservoirs, the continuity of the matrix is an important consideration. Much of the recent works on dual-porosity modeling are directed towards the more accurate representation of matrix-fracture transfers. In particular, the representation of gravity and capillary effects, capillary continuity or discontinuity of the matrix blocks, and the modeling of reimbibition phenomenon have received much attention.

Frequently, a fine-grid simulation (explicit discretization method) is used to evaluate the accuracy of a proposed transfer calculation. In such a simulation, the matrix blocks are discretized into several gridblocks. The adjacent fracture may also be discretized. The idea is that a fine-grid simulation can accurately represent the interplay of recovery mechanisms on the local scale and does not involve the assumptions of how matrix-fracture transfer ought to be calculated. However, in the field-scale simulation of these reservoirs, a fine-grid model is beyond the scope of today’s computer hardware capability. Therefore, some simplifications or lumping is required to keep the problem manageable. The paper will review several approaches documented in the recent petroleum literature, the approximations involved and their implications on the modeling of recovery processes in naturally fractured reservoirs. Based on the review, some suggestions are made as to the future development for this important area of reservoir simulation.
A Hostile Environment Gelled Polymer System for Well Treatment and Profile Control
Authors: Clampitt R. L. , Al-Rikabi H. M. , Dabbous M. K.
Published: December 2007

Profile modification by crosslinked polymer treatments can significantly reduce water production and increase oil production in producing wells and improve the injectivity profiles and reservoir performance in injection wells. Profile modification has been successfully applied to cased-hole as well as openhole completions, long to very short pay sections, and naturally fractured and hydraulically fractured formations. Reservoirs treated include bottomwater drive, edgewater drive, waterfloods, reservoirs under gas injection, and for casing-leak squeezes. Polymer treatments are equally applicable to sandstones and carbonate reservoirs.

A stable polymer crosslinked gel system suitable for reservoirs in hostile environments (high temperature, high salinity with very high divalent cations) was developed for multiple well treatments for profile modification. The stability of the gel was tested in the lab under reservoir temperatures for long periods of time, and proven in several field pilot trials.

Two types of treatments were evaluated. In the first type, organic crosslinkers (gelation agents) were used, and in the second type, nonorganic crosslinkers were used. The organic system was superior because it was easy to implement and control during field operations as a result of the flexibility in gelling time which allowed injection of the required amount of the polymer deep in the formation; and secondly, because of the ability to inject slow-gelling-time gel as diverter for batch treatments in a multizone interval with thick gross thickness.
Rock-Compaction and Pressure-Transient Analysis with Pressure-Dependent Rock Properties
Authors: Kohlhaas C.A. , Miller F.G.
Published: December 2007

Introduction

The equation generally used to describe unsteady-state fluid flow in porous media is the diffusivity equation porous media is the diffusivity equation either in terms of potential, head, pressure, or density. Terzaghi used pressure, or density. Terzaghi used the equation to describe changes of head within permeable layers of rock which resulted in fluid flow and rock compaction. Use of this equation to describe rock compaction requires the assumptions that permeability, porosity, formation compressibility coefficient, and formation thickness are constants. It is also assumed that grain volume is constant and that bulk-volume reduction equals pore-volume reduction.

Terzaghi's results have been applied to many engineering problems, including the compaction of oil-reservoir rocks due to fluid-pressure decreases caused by fluid withdrawals. For a horizontal, isotropic, homogeneous layer bounded on the top by an impermeable boundary and on the bottom by a high-permeability layer which acts as a drainage channel and in which there is a sudden drop of head from hi to ho at t = o Terzaghi gives the head as a function of time and distance:

(1)

Overburden loads are supported by a combination of the rock grain-to-grain "pressure", PG and the interstitial fluid pressure, Pf:

(2)

Compaction of the rock is a function of changes of PG, which is often designated "compaction pressure." From equation (2) therefore, it may be seen that rock compaction, designated "shrinkage" by Terzaghi, is a function of Pf if Pob is constant.
Multiwell Application of Downhole Temperature Profiles for Crossflow Analysis
Authors: Petricola M. F. J. , Watfa Mohamed
Published: December 2007

Temperature profiles have been used extensively for problem diagnostics related to downhole leaks and cross-flows behind the casing. The classical procedure is to obtain a true geothermal temperature profile and correlate future temperature changes to the geothermal to obtain an estimate of the location, magnitude and direction cf the cross-flow anomalies. This single well technique was limited by the availability of a representative geothermal gradient, local and time-lapse variations in this geothermal gradient, coupled with the absolute accuracy required from the temperature readings.

The technique presented in this paper looks at extending the single well temperature profile analysis to multi-well data-base application. Here the temperature profiles for a selected number of wells in a field are loaded in a database. The geothermal variations across the field can then be quantified at any given period of time from the median reading for the wells in that area. This allows for data normalizations for all the wells, which improved the accuracy of the temperature readings. The net effect is an order of magnitude improvement in accuracy, which facilitated the detection of small leaks and cross-flow of fluids behind the casing. In essence, this technique overcomes all the shortcomings and errors that are normally associated with the single well temperature profile evaluation.

The examples presented show the classical applications of temperature profile evaluation in a variety of behind the casing cross-flow environment. The results also show how a geothermal gradient can be obtained from a family of wells where no representative geothermal gradient is available over the intervals of interest. The resultant improvement in resolution also highlight the presence of very slow leaks, that would otherwise have not been detected.
Polymer-Augmented Waterflooding in a Reservoir With a Bottomwater Zone
Authors: Hodaie Homayoun , Bag~ci A. S.
Published: December 2007

In this paper the effect of preselected polymers on waterflooding of a limestone reservoir with or without bottom water zone, as well as the effect of vertical and horizontal production wells on oil recovery have been investigated in laboratory models. Sixteen core flood displacement tests were conducted to study the effect of relative oil-water layer thickness, slug size and well configuration in production port. A quantitative comparison was made to show the difference between waterflooding and polymer augmented waterflooding runs, where a light crade oil with a viscosity of 14.5 mPa.s was used.

Among six polyacrylamide samples of different ionic characteristics and molecular weights, the polymer with low ionic and medium molecular weight characteristics showed the best resistance and residual resistance factor behaviors during eight polymer flood tests and was selected for displacemet tests.

The results of the displacements tests showed that as the thickness of bottom water zone increases, the ultimate oil recovery decreases. Polymer solution had a favorable impact on the waterflood performance. However, the worse the conventional waterflood performance was, the more effective the polymer as mobility control agent. For polymer injection, the effect of slug size was discussed with the aid of concentration curves and retention rate values, and a slug of 0.6 PV was obtained as optimal. Using horizontal production well showed slightly better oil recovery than vertical production well in conventional waterflood of the reservoir model with a thin bottom water zone. However, in polymer augmented waterflooding oil recovery was less than that in vertical production well case. This was due to the early production of polymer solution and reduction of the swept area by polymer which was investigated by concentration curves as well.
Applications of VSP Inversion in Reservoir Characterization
Authors: Ahmed Shabbir
Published: December 2007

Improvements in downhole seismic data acquisition and processing techniques now make it possible to extract a high resolution formational impedance log at the well, from the VSP traces. The redundant information from VSP upgoing wavefield helps to enhance the signal-to-noise ratio and to restore true high frequency impedance information, through Entropy Minimization technique. The extracted acoustic impedance profile at the well is further used to invert the surface seismic traces, away from the well. The resulting acoustic impedance data not only shows accurately the stratigraphic variations of the subsurface away from the borehole, but also helps to characterize the key reservoir formations.
The Integration of Seismic and Well Data for Improved Reservoir Models
Authors: King G. A. , Archer S. H. , Seymour R. H.
Published: December 2007

The contribution that seismic data can make to the structural and stratigraphic model of a reservoir is well known, as is its ability to delineate fluid contacts in favorable circumstances. However, lithologic control in reservoir simulation models frequently are limited to information gathered at wells. Any advance in interwell correlation will strengthen the validity of the models. A practical constrained inversion technique is presented by which a seismic survey can be used to improve the estimates of lithology and porosity in undrilled areas of a reservoir on a scale appropriate for reservoir simulation modeling.

The input data for the constrained inversion technique are acoustic logs estimated from the wide band combination of borehole logs, seismic and geological data. The basis of the inversion method is to distribute conventionally interpreted borehole estimates of lithology and porosity throughout a field, guided by the existing seismic-geologic interpretation of the field's structure and stratigraphy. Selected petrophysical relationships and constraints are invoked in an iterative inverse procedure to perturb the lithologic and porosity models by the least amount necessary to explain the detailed seismic reflection amplitude data. The final result is a highly resolved lithologic and porosity model of the field, consistent with all available borehole, geologic and seismic data, suitable for use in field evaluation and for building reservoir simulation models. Also, these detailed estimates may be calibrated with core data to provide useful information about the permeability variation throughout the field. The technique is illustrated with a field data example from a three dimensional seismic prospect where complex reservoirs are present.
Description and Interpretation of North Sea Fractured Chalk Formations
Authors: Meling L. M. , Lehne K. A.
Published: December 2007

This paper describes novel methods for fracture description and implications by using well logs, core data, well tests and geological inteipretation.

The type, amount and orientation of fractures and fracture systems have major impact on field behaviour. We present methods to estimate in situ stress and fractures from logs. Fracture description from cores further enhance the proposed description of the fracture system. The paper also show how well test data give quantitative informations about fracture conductivity initially and during field depletion.

If fracture conductivity exceeds a fracture intensity threshold, separate matrix blocks occur. We identified such systems by a new method which identify individual capillary pressure systems and thereby individual matrix blocks. We also used the method to identify in situ wettability.

The methods presented in this paper we successfully used for some North Sea Chalk fields.
Application of Anti-Whirl PDC Bits Gains Momentum
Authors: Sinor L. A. , Warren T. M.
Published: December 2007

Over the past four years the phenomenon of bit whirl has been identified as a maj or cause of premature failure and reduced performance of PDC bits. Examples of the successful application of commercially available Anti-Whirl bits for straight hole rotary drilling, straight hole motor drilling and steerable directional drilling are presented. Also discussed are a number of features that may be used either separately or in conjunction with the Anti-Whirl design to help reduce the tendency to whirl.
A Systems Approach to Drilling Fluids Management Improves Drilling Efficiency: A Case Study on the NN Platform in the Arabian Gulf
Authors: Moore D. J. , Forbes D. M. , Spring C. R.
Published: December 2007

The NN - platform was drilled offshore Dubai in the SW Fateh field by Dubai Petroleum Company. As a total of 16 wells were drilled, a sharp learning curve was required to optimize drilling efficiency. Each well was drilled to a depth of +/- 10,000 ft using a gel based mud in top hole, with two thirds of the wells being completed to total depth (TD) utilizing a KCL polymer system and the remainder of the wells using a low toxic oil based mud (LTOBM) system. This paper focuses primarily on a systems approach to drilling fluids management and tries to establish the degree to which this affects drilling efficiency. Sharp learning curves were established through increased monitoring of the fluid and by integrating solids control efficiency with normal mud engineering practices. Particular attention to the cost per foot,mud usage, drilling time, and hole quality was used to determine drilling fluid performance. Any major changes in other drilling parameters (such as hydraulics or bit type) arereported. Since the monitoring of drillingfluids has not changed significantly in recenttimes, the question must be asked "how can sharper learning curves be establishedfor the future?". Hence, the second part of this paper will deal with future improvements regarding fluids monitoring at the rig site and what effects this might have ondrilling efficiency. Attention will be givento the data processing aspects and interpretation. Correlations to particular instances on the NN platform will be used as examples to illustrate the need for such measurementsand the value they will have on future drilling operations.
Natural and Induced Systems and Their Application to Petroleum Production
Authors: Pasini J. , Overby W.K.
Published: December 2007

The Morgantown Petroleum Research Laboratory, U.S. Bureau of Mines, is investigating the orientation of hydraulically induced fractures in petroleum reservoirs to help guide producers in better location and spacing of producers in better location and spacing of wells for more efficient fluid injection and petroleum production. The results of analyses petroleum production. The results of analyses of surface and subsurface information show a definite correlation between surface lineations and azimuths of hydraulically induced fractures. Joint systems determined from remote sensing imagery and/or surface surveys have been correlated with subsurface fracture orientations to depths of 3,000 feet and used to predict the bearing of hydraulically induced fractures in the Appalachian basin. Possible applications of fracture orientation Possible applications of fracture orientation prediction to petroleum production are also prediction to petroleum production are also discussed.

Introduction

One of the most important problems facing the domestic petroleum industry is the declining reserves to production ratio. Although additions to reserves through increased secondary recovery operations have nearly offset the decline in reserves added by drilling in recent years, there is a limit to the volume of crude oil that can be recovered through economic secondary means. A large fraction of our oil reserves, both primary and secondary, are contained in low permeability formations from which they cannot be economically produced by present techniques. Although the development of hydraulic fracturing has enabled the industry to develop a portion of these reserves, little is really known about the system of fractures created or the effect of natural fractures on fluid flow. Planes of weakness, which could be opened Planes of weakness, which could be opened during secondary recovery operations or hydraulic fracturing, do exist and have a preferred compass orientation. The effect preferred compass orientation. The effect of induced fractures on fluid movement in the reservoir must be known to attain maximum production efficiency. production efficiency. The Morgantown Petroleum Research Laboratory of the U.S. Bureau of Mines initiated a study in 1967 to investigate hydraulically induced and natural fracture systems and their effect on crude oil recovery. Results of these investigations will be used to locate wells in secondary recovery projects to obtain the highest injection rates and breakthrough sweep efficiencies possible and, in areas under primary recovery, to make maximum use of the primary recovery, to make maximum use of the drainage capabilities of the hydraulically induced fractures.
Geologic Factors Which May Affect the Occurrence of Natural Gas in the Oklahoma Panhandle
Authors: Moore Carl A.
Published: December 2007

Introduction

The Oklahoma Panhandle was once called "no man's land" because it was a narrow strip of land of doubtful value lying between Kansas and Texas.

Geologically, the Oklahoma Panhandle is situated along the northwest flank of the Anadarko Basin and separates the Dalhart Basin from the Hugoton Embayment of the Anadarko Basin. This is a geographic separation rather than a tectonic separation. As a result, the Panhandle has been subject to a basin-flank Panhandle has been subject to a basin-flank geological history as compared with the basin troughs on either side.

Initial production of natural gas in the Oklahoma Panhandle was from rocks of Permian age: the Herington, Krider and Winfield porous limestones and dolomites in the Hugoton field. Production came from above 3,000 ft [drilled Production came from above 3,000 ft [drilled depth] and many wells were rated as being major producers. producers. Prior to the early 1950's, there had been only limited, sporadic production from reservoirs older than the Permian. With the discovery of gas in Beaver County [eastern county in the panhandle] in upper Pennsylvanian limestones, major development and exploitation of other Pennsylvanian and Mississippian horizons quickly Pennsylvanian and Mississippian horizons quickly followed.

In addition to the Permian production in the Oklahoma Panhandle, variable production has been found in the Pennsylvanian rocks: Wabaunsee, Hoover, Tonkawa, Topeka, Kansas City lime, Toronto, Douglas, Council Grove, Hodges, Lovell, Des Moines, Oswego, Marmaton, Cherokee, Morrow, Purdy, Keyes, Collier, Atoka, basal Pennsylvanian; Mississippian: Chester, Meramec Pennsylvanian; Mississippian: Chester, Meramec and Devonian Hunton. Some of these beds are correlative, being local names of a given horizon. The Morrow is by far the most important of this list,, followed by the Chester, the Hoover, Tonkawa and Topeka in approximately equal proportions.

REGIONAL GEOLOGY

Fig. 1 illustrates the subsurface structure across the Oklahoma Panhandle as shown on the datum at the base of the Pennsylvanian system of rocks. Starting in the western part, in Cimarron County, depths to the pre-Pennsylvanian sequence of rocks average some 1,000 ft below sea level. Because of the lack of drilling, this part of the county is poorly known. One fault probably related to the faults in Texas County, is shown. Keyes Dome is situated within the closing contour in the northeast corner of Cimarron County.

Differences in subsurface elevations across Texas County range from 1,000 ft to 4,400 ft below sea level.
Lithology-Dependent J-Functions and Relative Permeabilities
Authors: Phelps R. E.
Published: December 2007

This paper demonstrates a technique of using log data coupled with lithology dependent porosity-permeability transforms to calculate facies-dependent Leverett J-functions for the Hadriya reservoir. A comparison of initial water saturation profiles from formation analysis logs versus profiles from a single global J-function and facies-specific J-functions are presented.

These facies dependent J-functions were then used to compute facies specific imbibition and drainage relative permeabilities for both the wetting and non-wetting phase.
Interpretation of the Transient Pressure Recorded by a Multiprobe Wireline Formation Tester in a Layered Reservoir
Authors: Shah P. C. , Thambynayagam R. K. M. , Pop J. J. , Pelissier-Combescure Jacques , Heliot Denis
Published: December 2007

The deconvolution of the transient pressure response recorded by one monitor probe (the v or "vertical" probe) of a multiprobe formation tester with respect to that recorded by the other probe (the h or "hor-izontal" probe) yields the Pv/Ph transfer function. The transfer function response is independent of the flow rate variation and local effects in the vicinity of the sink probe and hence offers an attractive diag- nostic/interpretation technique. However, the complete theoretical transfer function response has not been calculated and systematically studied even for the simplest case of a wellbore located in a homogeneous infinite reservoir. This paper contains a limited catalog of responses, which account for the wellbore, for reservoirs that are homogeneous, infinite or finite, have one or two layers, and have a thin shale streak present between the h and v probes. A systematic study is made of the variation of this response with the formation, fluid and geometric parameters of the model.

This study has led to the conclusions that the existence and location of layer boundaries and shale streaks must be independently known from other measurements (openhole logs or borehole images) before inverting for the anisotropic permeabilities. A simultaneous inversion of the geometric parameters and the permeabilities will most likely result in nonuniqueness. For example, if the data from a formation with layering are interpreted using a homogeneous model, the resulting permeability anisotropy estimates may be in significant error. Moreover, very different physical situations often lead to very similar Pv/Ph transfer functions, and thus the risk is high that a diagnosis is incorrect when it is made solely from the transfer function obtained by deconvolving the measured pressure responses.

An example with field data is presented, and the transfer function derived from the measured pressure transients through deconvolution is compared with the theoretical response of models obtained by pressure history-matching.
Transient Testing of Limited-Entry Wells in Communicating Layered Reservoirs
Authors: Abbaszadeh M. D. , Tomita Nobuhiko , Tanaka Tatsuo
Published: December 2007

This paper presents both theory and field application for well testing of single or dually completed limited-entry wells in layered reservoirs. A comprehensive analytical solution is developed which considers anisotropic layers with crossflow among layers in the formation. Features of the model are discussed and sensitivity studies are presented to illustrate effects of contrast in layer properties, dual completion, and geometry of limited-entry wells on transient responses. Some behavior of interference tests for different well completion geometries are also studied.

An interpretation method is presented which characterizes high and low permeability layers from pressure transient data. A field pressure buildup test from a layered reservoir, where a high permeability layer is between two low permeability layers and the well is partially completed in a low permeability zone, is analyzed by the interpretation method of this paper. Properties of high and low permeability layers are computed from this single buildup test
Transient Pressure Analysis for Wells in Multilayered Reservoir with Finite Conductivity Fractures
Authors: Osman M. E.
Published: December 2007

In this study, a mathematical model was developed to present the pressure behaviour of a well located in a multilayered infinite acting reservoir and crossed by a finite conductivity vertical fracture. It was found that dimensionless pressure functions and it's derivative are strong functions of fracture conductivity and extension during early time. The effects of reservoir heterogeneity on pressure function are negligible compared to their affects on the pressure derivative. It was also found that fractional production rate from different layers is a good measure of reservoir and fracture characteristics. Flowmeter survey data can be used to eliminate uniqueness problems in using type curves presented in this study.
Successful Applications of the Multilayer Transient Testing Technique: Arab-C Members of the Umm Shaif Reservoir
Authors: Khalaf A. A. , El Emam M. , Mahmoud Y. , Saeedi Jawaid
Published: December 2007

The Multi-Layer Transient Testing technique (MLT) was implemented in deviated wells with relatively low potential in order to estimate the layer production capacity (Kh), skin and pressure in the commingled production of Arab-C different sub-layers. For each MLT, a pair of rate and pressure transient were acquired over each member when the surface flow rate was changed systematically.

This paper discusses the successful use of the MLT technique as a monitoring tool in Arab-C reservoir of the Umm Shaif field. The rate and pressure transients were used to identify the reservoir model using the rate normalized pressure derivatives. Whilst the parameter estimates were obtained using the Sandface Rate Convolution (SFRC) plots and pressure derivative matches to the convolution type curves. The layer estimated parameters were used with a single well numerical model to calculate the bottom hole pressure (BHP) response during the test. A match to the measured BHP response gave the final parameter estimates.
Logging Experience with the Pulsed Spectral Gamma Tool
Authors: Wyatt D. F. , Jacobson L. A. , Fam Maged
Published: December 2007

A newly introduced pulsed spectral gamma-ray (PSG*) logging tool utilizes a high-density bismuth germanate (BGO) scintillation detector to improve the log measurement. The traditional limitation of the carbon/oxygen (C/O) measurement is its poor statistical performance due to the small dynamic range of the measurement. This limitation is significantly reduced by the improved sensitivity of the bismuth germanate detector to high-energy gamma-rays.

Chaxts based on extensive laboratory measurements characterize the tool response to porosity, lithology, fluid type and borehole conditions. The C/O ratio shows a dynamic range of 22% at 35 pu in a 10-in borehole. It is relatively insensitive to variations in casing size and weight, and cement type and thickness. Field logging experience demonstrates that, compared to older C/O tools, the improved capabilities of the PSG tool enables either recording acceptable logs at higher logging speeds (5 ft/min) or better saturation precision at slower speeds (1 to 2 ft/min) than was previously possible. Logging speed can be at least tripled while obtaining precision Comparable to older tools. Capture spectral processing to obtain relative elemental yields is provided and aids in lithology interpretation.

Several logs from wells in both Nigeria and Alaska illustrate log presentation formats and the quality of the measurements under a variety of logging environments. Oil saturation calculations using only PSG data and using PSG data plus porosity from open-hole logs correlate well with open-hole oil saturation predictions. Complex lithology evaluation is available through ULTRA* and is compared to open-hole results. Merging multiple passes improves the quality of the oil saturation determination. Five-minute station measurements are compared to continuous logs and show satisfactory correlation. Generally, statistical uncertainties for logs run at an effective logging speed of 2 ft/min or less are dominated by systematic uncertainties from environmental effects. Several log quality indicators that monitor hardware spectral gain stabilization and offset and software functions (curve statistical precision) are available in real time.
In-Situ Determination of Oill/Water Relative Permeability Curves Using Well Performance Data
Authors: Al-Khalifa A-J . A.
Published: December 2007

This paper describes a new method to estimate oil-water relative permeability in-situ, using well performance data. The historical production rates of an oil producer reflected in a time-lapse of successive flowmeters are used to estimate the oil-water relative permeabilities. The corresponding water saturations are obtained through saturation logs or computed using the cumulative production volumes in a Buckly-Leverett solution.

The proposed method is a major improvement over current historical performance methods. This method yields the individual oil and water relative permeability curves, rather than the ratio of oil to water permeability curve obtained using other techniques. Furthermore, this method results in different relative permeability curves for different facies as they are swept at different times.

The resulting relative permeability curves reflect the properties of the whole drainage area, rather than those of a small laboratory core. They also reflect true reservoir conditions, accounting for wettability, heterogeneities and fluid compositions. Therefore, they yield a better modelling result with minimal changes in the history matching process.

The proposed method is demonstrated using field data of a giant carbonate reservoir under a major water flooding project. Field results presented in this paper demonstrate the ease and the applicability of this method.
Estimation of Residual Oil Saturation (ROS) on a Field-Wide Basis Using Multiwell Data-Base Techniques
Authors: Reiss A. R. , Watfa Mohamed , Plomb J-P.
Published: December 2007

The estimation of ROS is essential for a variety of applications in the oil industry. This application varies from the requirement of ROS input to the reservoir simulation, to the estimation of the recoverable hydrocarbon volume. A knowledge of the ROS is also essential for evaluating the sweep efficiency of the reservoir, and correspondingly for the evaluation of the unswept hydrocarbon volume. A variety of techniques were used in the past for the evaluation of ROS which included core analysis, Log-Inject-Log techniques, and saturation monitoring of zones which have been swept by the production process. Invariably, these techniques yielded results which at best are representative of single wells and over small intervals.

The technique presented in this paper looks at using multi-well data-base statistical techniques to estimate the ROS. The approach is to collect the known data on ROS from Thermal Decay Time Log (TDT*) data and open hole data over swept intervals which is not perforated or acidized.; such data is normally scattered over small intervals from different wells. The next step is to use this data in a multi-dimensional statistical data-bank to obtain ROS values over most of the logged intervals, and in wells where no ROS data is available. The Data-Bank statistical correlations are used to find correlations between the ROS and the various log and log-derived interpretations, and then to extrapolate this knowledge to estimate ROS data across the field. Such techniques have been applied successfully to estimate permeability variations across all the logged intervals in large reservoir.

This approach is definitely a big step forward in understanding the variations of ROS. In the limit. the results obtained can be used as a first order approximation of ROS. Accuracy of the results obtained can be tested by estimating ROS in wells where some ROS values are available and to estimate the errors by comparison with true data. The availability of a representative volume of estimated ROS data on a field wide basis can facilitate the drawing of ROS maps for the various layers and sub-layers in a producing reservoir.
Rigsite Ions Monitoring System for Drilling Fluids
Authors: Hughes T. L. , Jones T. G. J. , Geehan Thomas , Tomkins P. G.
Published: December 2007

Chemical composition is a critical factor determining the performance of water-based drilling fluids. During drilling, the circulating fluid undergoes chemical changes due to additions of mud products at surface, interactions with drilled formations and losses of fluid in discharges and on drilled cuttings. Chemical changes due to interactions with drilled formations may degrade the performance of the drilling fluid. Rigsite tools to monitor chemical composition as well as functional properties are required for optimum maintenance of a fluid specification during drilling.

A rigsite system to monitor and control the ionic composition of water-based drilling fluids is presented. The system consists of (i) a measurement component which provides frequent determinations of the ionic composition of the aqueous phase of the fluid during drilling and (ii) an interpretation component which includes software for calculation of filtrate density and water activity, an advisor tool for designing fluid treatments and a data storage and processing package for constructing chemical logs during drilling.

The Measurement component has two units; a cross-flow filtration unit for rapid preparation of filtrate from representative samples of the fluid entering and exiting the wellbore during drilling and an ion chromatography unit for rapid and accurate analysis of filtrate composition. The ionic compositions of filtrates prepared using the cross-flow filtration unit and a standard API static filtration apparatus are compared. Further laboratory and pilot-scale tests involving controlled additions of inorganic salts to simple water-based drilling fluids simulate chemical changes in fluid composition and provide data with which to assess measurement accuracy and precision. The use of the Interpretation component for calculating water activity and as an advisor tool in designing treatments to control fluid composition is described.

Results from field case studies emphasise the importance of chemical monitoring in an optimum drilling fluids engineering service. Correlations between the chemical composition and functional properties of water-based drilling fluids are discussed with particular reference to the effect of divalent cations on the efficiency of water-soluble polymers.
A New PDC Cutting Structure Improves Bit Stabilization and Extends Application into Harder Rock Types
Authors: Weaver G. E. , Clayton R. I.
Published: December 2007

The destructive effects of the dynamic forces typically induced by the cutter/rock interaction of PDC bits have been identified in previous works. The material presented in this paper deals with a new cutting structure developed for PDC bits which is self-stabilizing; forcing the center of rotation to remain at or near the bit's design center.

Positioning the PDC cutters in concentric rings with little or no overlap between cutters produces a bottom hole profile with deep grooves. These grooves act as guide tracks for the PDC cutters and provide a restoring force to resist off-center rotation.

This paper describes the design and testing of whirl resistant PDC bits based upon these design principles. Laboratory drilling experiments are discussed and conclusions developed which are validated with field performance in six case histories.
Estimating Secondary Reserves
Authors: Amyx J.W. , Bass D.M.
Published: December 2007

1962 Economic and Valuation Symposium Dallas, March 15–16, 1962

Introduction

The estimation of secondary reserves unfortunately cannot be reduced to a simple, standard procedure wherein all factors or parts are automatically specified once a process has been selected. This paper will discuss the general procedure and factors which must be considered in estimating secondary reserves. Before any discussion pertaining to estimation of reserves, it is necessary to define the terminology.

Reserves, as used herein, is that quantity of oil which is yet to be reduced to possession by the production procedure in operation.

Ultimate or Total Reserves is that quantity of oil which can yet be reduced to possession by either the existing or augmented operational procedure.

Primary Reserves is that quantity of oil which is yet to be reduced to possession soley by means of the naturally occurring reservoir energies under the existing competitive and regulatory conditions.

Secondary Reserves is that quantity of oil in excess of primary reserves which is yet to be reduced to possession by supplementation of the naturally existing reservoir energy.

Ultimate Recovery is that quantity of oil which will be reduced to possession during the operational life of an oil reservoir.

Primary Recovery is that quantity of oil which will or could be reduced to possession in an oil reservoir's producing life utilizing only the naturally occurring reservoir energy.

Secondary Recovery is that quantity of oil in excess of the ultimate primary recovery which will be reduced to possession because of the supplementation of natural reservoir energy. It is the difference between ultimate and primary recovery.

For the foregoing definitions, general equations can be written to express the relationship between ultimate, primary and secondary recovery and primary and secondary reserves. The most general form of these equations are

Ultimate Recovery

(1) = ( EA EV Ed ) N= ( ER ) UN

Primary Recovery

(2) = ( ( Ed )  p ( EA )  p ( EV ) p ) N= ( ER ) p N

= (EA) ij (EV) ij (Ed) ij) (N-Np0 pj)

- (ER)p - (ER) pj) N

or

= (ER) ij (N - (Np) pj)

(3) − ( ER ) p N − ( Np ) pj )

Reserves at time k

(4) = ( ER ) UN − ( Np ) k

Primary Reserves at time k

(5) =  ((ER)p  −  (ER) pk) N =  ((ER0p N  −  (Np) pk)

Secondary Reserves at time k

(6) =   ( ER ) ij  ( N − ( Np ) pj ) − ( ( ER ) p N − ( Np ) pj ) − ( ( Np ) k − ( Np ) pk )

P. 36^
Steady-State Bitumen-Water Relative Permeability Measurements at Elevated Temperatures in Unconsolidated Porous Media
Authors: Bennion B. , Sarioglu Gurk , Chan M. Y. S. , Hirata Toshiyuki , Courtnage Dave , Wansleeben John
Published: December 2007

Accurate drainage and imbibition relative permeability data are essential for the accurate prediction of the performance of heavy oil reservoirs undergoing cyclic steam stimulation or steam drives. There is very little published data regarding steady state relative permeability measurements at elevated temperatures. This paper documents two complete water-bitumen steady state drainage and imbibition tests conducted at a temperature of 200° C at full reservoir pressure and overburden conditions utilizing composite core stacks of actual, preserved reservoir core material. The test results indicate substantial hysteresis effects in the non-wetting (bitumen) phase and provide insight into the wettability, displacement efficiency, residual saturations and endpoint permeabilities and relative permeabilities for an unconsolidated heavy oil sandstone reservoir.