bluuebunny/crossref_metadata_2025 huggingface dataset:
A Consistent Probabilistic Definition of Reserves
Authors: Capen E. C.
Published: December 2007

Uncertainty begs for a probabilistic treatment, and I know of almost no business filled with more uncertainty than that of the petroleum technologist in quest of oil and gas volume estimates. As in most uncertain endeavors, no single number captures the range that describes our lack of knowledge. Fortunately, the petroleum business has a mathematical ally, the central limit theorem. We know when we multiply variables (reservoir thickness, reservoir length, reservoir width, porosity, saturation, percent of hydrocarbon in place that can be produced with present technology and prices), we very quickly approach the log-normal distribution. We can make our estimates of proved, probable, and possible reserves all consistent if we make sure that each lies on the same log-normal probability distribution. We make still other improvements if we take these distributions for wells (or the basic unit on which we estimate reserves) and add the entire distribution to get reservoir, field, or company reserves. Simply adding proved reserves has never been a mathematically legal operation and ought to cease as quickly as possible. By striving for a distribution answer, we will find that we supply the kinds of numbers from "very safe" to "this is a dream" that will satisfy the various constituencies requiring volume information—governments, management, explorationists, bankers, and others. Still better, when estimates have probabilistic definitions, it is also possible to generate performance measures that hold the estimators to their promises.
Hydraulic Fracture Performance in the Moxa Arch Frontier Formation
Authors: Cipolla C. L. , Meehan D. N. , Stevens P. L.
Published: December 2007

A comparison of hydraulic fracture performance during the initial development of the Moxa Arch Frontier sandstone in southwestern Wyoming (1975 to 1985) through infill development in 1989 to 1991 (320-acre spacing) and 1992 (160-acre spacing) is presented. The evaluation includes 3D hydraulic fracture modeling of reflected bottomhole pressures measured on 36 wells completed in 1992. In addition, in-situ stress test results from two wells are integrated with 3D fracture modeling and reservoir simulation of postfracture well performance to evaluate the evolution of fracture treatments over 17 years of development.

The results from over 200 fracturing treatments were used to quantify the effect of treating fluid and proppant type on well performance. Detailed 3D fracture modeling illustrates the effects of in-situ stress and leakoff properties on fracture geometry. The results from 3D fracture modeling of 33 mini-fracs indicates vastly different fluid-loss behavior from well to well and a variation of in-situ stress within the Moxa Arch. The performance of 1992 infill wells stimulated with guar-based gels (borate and zirconium crosslinked) and sand is similar to initial development wells stimulated using guar-based crosslinked polymers and sand. However, 1989 to 1991 infill wells stimulated using CO2 foam and intermediate-strength ceramic proppants (ISP) did not perform as well as the water-based fluids and sand treatments. Fracturing net pressure data are presented that illustrate excess pressures owing to "proppant effects" and breakdown of stress barriers during fracturing that occurs in many treatments.
A Mechanistic Model for Computing Fluid Temperature Profiles in Gas-Lift Wells
Authors: Hasan A. R. , Kabir C. S.
Published: December 2007

In a continuous-flow gas-lift operation, gas is injected down the annulus into the tubing near the top of perforations. The intrinsic idea is to aerate the liquid column, thus providing the necessary stimulus for fluid flow. Because the volumetric gas rate is dependent upon both the pressure and temperature at the depth of injection, accurate knowledge of these entities cannot be overemphasized for an efficient lift. In particular, the behavior of the nitrogen gas charged in the dome is critically dependent upon the temperature prediction for the optimal performance of the bellows-charged gas-lift valves.

Current practice entails use of a linear temperature profile for the annular fluid while applying empirical correlations for the tubing fluids. Improved temperature predictions are now possible for fluids in both conduits by modeling the heat and fluid flow problem at hand from first principles.

In this work, we present a mechanistic model for the flowing temperature of the annular gas and the gas/liquid two-phase mixture in the tubing as a function of both well depth and production time, regardless of the well deviation angle. The model is based on energy balance between the formation and fluids flowing through each conduit. While flowing down the annulus, the cold gas injected at the wellhead continues to gain heat. The heat-transfer rate for the annular gas depends on the relative temperatures of the formation and the tubing fluid. We assume unsteady-state heat transfer in the formation and steady-state heat transfer in the tubular for a continuous-flow gas-lift operation.

The analytic solution obtained affords flexibility to input any temperature distribution function (TD model) for modeling unsteady heat transfer in the formation. Rapid implementation of the new solution is possible because of its simplicity. Our results show that the temperature profiles in both flow conduits are nonlinear, unlike those used previously, particularly in the annulus. Variables, such as the overall heat-transfer coefficients, gas mass-fraction in the tubing, well depth, and flow rates, in both conduits govern the nonlinearity in temperature profiles. We discuss both synthetic and field examples to illustrate the applicability of the new solution.
Estimation of Permeability From Well Logs Using Resistivity and Saturation Data
Authors: Saner Salih , Kissami Mimoun , Nufaili Subhi Al
Published: December 2007

An experimental relationship between permeability, water saturation, and rock resistivity has been suggested. This relationship can be used for interpreting any one of these three parameters when the other two are known. For example, the relationship can be used in interpreting permeability from resistivity logs when water saturation is known. This study is based on electrical measurements of core samples of different permeabilities.

Brine saturation, SW, and corresponding rock resistivity, Rt, were used together to express the permeability of the rock. To eliminate the brine-resistivity effect, the rock resistivity was represented by an apparent formation factor, Fa, which is the ratio of the partially saturated rock resistivity to the brine resistivity, Rw. It was observed that the apparent formation factor vs. water-saturation curves for samples of different permeabilities were arranged similarly to capillary pressure curves, and each permeability is represented by a unique curve. Therefore, permeability was expressed as a function of the apparent formation factor and the brine saturation. When fractional brine saturation is 1.0, permeability becomes a function of formation factor only.

Water saturation and apparent formation factor are the parameters that can be calculated from well logs. When water saturation and apparent formation factor are known, permeability can be estimated from the suggested relationship. Data points from the oil zone, transition zone, or water zone can be used for computations. Permeability determinations are sensitive to the accuracy of water-saturation data near irreducible water saturations, although at high water saturations, accuracy of resistivity measurements becomes more significant for correct permeability results.
Hole-Cleaning Capabilities of Water- and Oil-Based Drilling Fluids: A Comparative Experimental Study
Authors: Hemphill Terry , Larsen T. I.
Published: December 2007

Many laboratory studies evaluating the cuttings transport capabilities of water- and oil-based drilling fluids have been published, but few attempts have been made to investigate both fluid types under identical, controlled conditions. Those that considered both fluid types measured cuttings accumulation in the annulus and not fluid velocity. In this comparative study, the efficiency of water- and oilbased muds in cleaning the inclined annulus at varying fluid velocities was investigated. The results showed that, under equivalent rheological and flow-velocity profiles, water- and oil-based drilling fluids clean similarly. While fluid velocity is key to hole cleaning, other parameters, such as mud density and flow index ‘n' factors, can affect cuttings transport efficiency in certain hole angle ranges.
Drilling-Induced Lateral Shifts Along Pre-Existing Fractures: A Common Cause of Drilling Problems
Authors: Maury Vincent , Zurdo Christian
Published: December 2007

Two gas well collapses showed a peculiar failure mechanism. Excessive fluid levels and temperature variations during the ultimate drilling phase and later workovers induced microannuli and cementation damage. Abnormal fluid pressures from deeper gas- or water-bearing layers channeled through damaged cementation and increased the pore pressure in uphole faults or bedding joints. Thus the effective normal stress on faults was released, inducing shear displacements and casing deformation. Weakened casings were further collapsed by later fluid-level variations.

It was then suspected that this mechanism also occurred in open holes during drilling. This was shown to be so with borehole televiewer tool (BHTV) images showing borehole lateral shifts. Although never mentioned in the past in the domain of borehole stability, this mechanism explains some poorly understood drilling incidents, such as tight-holes, problems to run in hole (RIH) or pull out of hole (POOH), and abnormal torques, in spite of no indications of instability, such as cavings. This mechanism can be mitigated by taking the necessary precautions during drilling and by the adequate selection of mud characteristics.
Predicting Phase Behavior of Water/Reservoir-Crude Systems With the Association Concept
Authors: Shinta A. A. , Firoozabadi Abbas
Published: December 2007

An association model has been incorporated in the Peng-Robinson equation of state (PREOS) to use the combined model for water/res-ervoir crudes phase-behavior calculations. The interaction coefficients between H2O and hydrocarbons follow a simple relationship. Such a relationship makes the use of the association equation of state (AEOS) both accurate and simple. The computed high-pressure crude/steam distillation results by the AEOS are in excellent agreement with the data.
Well Configurations in Anisotropic Reservoirs
Authors: Economides M. J. , Brand C. W. , Frick T. P.
Published: December 2007

Horizontal wells have emerged as a new means for well-productivity enhancement. Simultaneously, they have brought forward the need to recognize and account for permeability anisotropies, including vertical-to-horizontal and horizontal-to-horizontal directions. In addition, there is the possibility of multiple horizontal drainholes emanating from the same vertical well. Performance relationships for the most interesting well configurations are presented, including both early-time and late-time differences rather than only bounded flow regimes. Solutions for arbitrarily oriented single or multiple horizontal wells are introduced, along with a discussion of well-known existing relationships.
On the Mechanical Stability of lnclined Wellbores
Authors: Zhou Shaohua , Hillis R. R. , Sandiford Mike
Published: December 2007

Consideration of the stress field around an arbitrarily oriented borehole shows that in an extensional stress regime (σv σH>σh), wellbores parallel to the direction of minimum horizontal principal stress are the least prone to compressive shear failure (breakout). The most stable deviation angle (from the vertical) depends on the ratio of the horizontal principal stresses to the vertical stresses, and the higher the ratio σH/σV, the higher the deviation angle for minimizing breakout. In a strike-slip stress regime (σv <σH>σh), horizontal wells are the least prone to breakout, and the higher the ratio σH/σ v, the closer the drilling direction should be to the azimuth of σH.

A new compressive shear failure criterion, which is a combination of the effective strength concept and the Drucker-Prager criterion, is proposed for quantifying the stresses at which borehole breakout occurs. The lowest mud weight, at and below which breakout will occur, can be predicted by combining this criterion with the stress field around an arbitrarily oriented borehole. The highest mud weight at and above which a tensional or hydraulic fracture is induced can be predicted by combining the tensile strength of the rocks of the wellbore wall with the stress field around an arbitrarily oriented borehole. For the in-situ stress environments considered, the optimally oriented inclined wellbore is less prone to breakout (i.e., allows a lower mud weight) and tensional or hydraulic fracture (i.e., supports a higher mud weight) than a vertical well.
Zirconium Additives for High-Temperature Rheology Control of Dispersed Muds
Authors: Miano Fausto , Carminati Stefano , Lockhart Thomas P. , Burrafato Giovanni
Published: December 2007

Environmental considerations have stimulated new interest in the use of aqueous drilling fluids in situations where oil-based muds have previously been preferred. The least expensive and most widely used aqueous drilling fluids are dispersed muds made up with bentonite clay. These bentonite muds, however, possess limited rheological stability at elevated temperature and are also often formulated with chromium-containing thinners that are increasingly subject to environmental regulation.

This paper describes a new zirconium-based rheology control additive of low toxicity that is extremely effective at extending the rheological stability of both chromium-containing and chromium-free bentonite muds at high temperature. The results of mud-aging experiments carried out between 150 and 200°C on both laboratory and field-conditioned bentonite muds illustrate the rheology-stabilizing characteristics of this additive. The low cost of drilling fluids formulated with the zirconium additive makes them attractive candidates for resolving the environmental issues and limited rheological stability of existing bentonite muds.
Transport in Shales and the Design of Improved Water-Based Shale Drilling Fluids
Authors: van Oort Eric , Hale A. H. , Mody F. K. , Roy Sanjit
Published: December 2007

Transport of water and ions in shales and its impact on shale stability were studied to facilitate the improvement of water-based muds as shale drilling fluids. Transport parameters associated with flows driven by gradients in pressure and chemical potential were quantified in key laboratory and full-scale experiments. The experimental results show that the low-permeability matrices of intact, clay-rich shales can act as imperfect or "leaky" membranes that will sustain osmotic flow of water. Moreover, the ability of shales to act as osmotic membranes is shown to provide a powerful new means for stabilizing these rocks when exposed to water-based drilling fluids. Guidelines are presented for effective exploitation of shale membrane action and induced osmotic flows through optimized water-based drilling fluid formulation.

In addition, special attention is given to induced electro-osmotic water flow in shales driven by electric potential gradients, which may provide an exciting, new, environmentally benign means for stabilizing shale formations.
Tracer Flow and Pressure Performance of Reservoirs Containing Distributed Thin Bodies
Authors: Sato Kozo , Abbaszadeh Maghsood
Published: December 2007

The effects of thin objects (fractures/barriers) on pressure distributions and displacement performances in staggered and direct linedrive patterns with uniformly and stochastically distributed objects at different density and length distributions are studied. Tracer breakthrough and well productivity are used to characterize the configuration of thin objects in the patterns. In most cases examined, tracer breakthrough time is more sensitive to the presence of thin objects than the well productivity. It is also found that representing fracture systems as equivalent anisotropic media may lead to erroneous pressure-distribution predictions around a well.

The study was carried out by using the complex variable boundary element method (CVBEM), which yields both the potential and stream functions simultaneously, and is suitable to track displacement fronts in the presence of thin objects. Singularities caused by such objects are expressed analytically through the conformal-mapping technique.
Use of Geology in the Interpretation of Core-Scale Relative Permeability Data
Authors: Ringrose P. S. , Jensen J. L. , Sorbie K. S.
Published: December 2007

A number of factors, such as wettability, pore-size distribution, and core-scale heterogeneity, are known to affect the measured relative permeability in core plug samples. This paper focuses on the influence of geological structure at the laminaset scale on water-oil imbibition relative permeability curves. The endpoint positions and curve shapes vary as a function of the type of internal heterogeneity, the flow rate, and the assumptions on the pore-scale petrophysics (e.g. wettability). Interaction between the capillary forces and heterogeneity can occur at the cm-dm scale, which results in widely varying two-phase flow behavior for rocks with the same single-phase permeability. The geometry of heterogeneity as expressed in standard geological descriptions (e.g., cross-laminated, ripple-laminated, plane-laminated) can be translated into features of the expected relative permeability behavior for each rock type, thus aiding the interpretation of relative permeability data. We illustrate how our findings can help to interpret sets of relative permeability data from the field, using some examples from the Admire sand, El Dorado Field, Kansas.
Water-Droplet-Size Determination for Improved Oil-Treater Sizing
Authors: Thro M. E. , Arnold K. E.
Published: December 2007

The sizing of crude-oil treaters is still very much an art. While it is possible to perform laboratory studies on crude-oil samples, no one has published a proven field-test procedure that can be used to pick an appropriate treating temperature and treater dimensions for a specific field.
Dehydration and Desalting of Heavy and Viscous Crude Oil Produced by In-Situ Combustion
Authors: Popp V. V. , Dinulescu V. D.
Published: December 2007

This paper presents the dehydration and desalting of heavy crude oil produced by in-situ combustion with thermochemical and gas stripping stages. Indirect heating of oil through cocurrent contact with recirculated water from the process, heated with metal heaters, will preclude temperature variations caused by flow fluctuations in the feeding of the plant during the thermochemical process. At the same time, the amount of mechanical impurities (carried out by the recirculated water) is diminished. The flue gas stripping stage increased the process efficiency using a double column and blown-in air heater.
Phase Splitting Of Wet Steam in Annular Flow Through a Horizontal Branching Tee
Authors: Chien Sze-Foo
Published: December 2007

A phase-splitting equation for flow of a two-phase fluid through a tee junction was derived. It shows that the fluid quality at an outlet of the tee is determined by the relationship between the liquid and vapor extraction ratios of the fluid through that outlet. This equation applies to any tee junction regardless of its geometry, orientation, and inclination. This paper presents its application to the flow of wet steam through a horizontal branching tee.

Experimental data were for wet steam flowing through a standard branching tee of 2- and 4-in. sizes in a horizontal plane, inlet pressures from 400 to 800 psig, inlet qualities from 0.2 to 0.8, inlet vapor velocities from 40 to 120 ft/sec, and for vapor-extraction ratios in the 0.2 to 0.8 range. These data were analyzed focusing on the effect of the vapor-extraction ratio of the run stream on the liquid-extraction ratio of the same stream. A correlation between these two extraction ratios has been established with steam quality, superficial vapor velocity, and critical velocity at the inlet to the tee as controlling parameters. Using this correlation and the phase-split equation, we are able to predict steam qualities exiting from horizontal branching tees to within ± 15% of the experimental values, which is more accurate than other phase-splitting models.
Modeling and Scaleup of S†eamflood in a Heterogeneous Reservoir
Authors: Dehghani Kaveh , Basham W. M. , Durlofsky L. J. , Tucker K. E.
Published: December 2007

A series of simulation runs was conducted for different geostatistically derived cross-sectional models to study the degree of heterogeneity required for proper modeling of steamfloods in a thick, heavy-oil reservoir with thin diatomite barriers. Different methods for coarsening the most detailed models were applied, and performance predictions for the coarsened and detailed models compared. Use of a general scaleup method provided the most accurate coarse grid models.
Performance and Expansion Plans for the Double-Displacement Process in the Hawkins Field Unit
Authors: Langenberg M. A. , Henry D. M. , Chlebana M. R.
Published: December 2007

The double-displacement process (DDP) is a method for immiscible tertiary gas displacement of a watered-out oil reservoir. In the Hawkins field of east Texas, the effectiveness of the immiscible nitrogen injection process is strongly driven by favorable gravity-drainage characteristics that lead to improved sweep and displacement efficiencies for the gas/oil system relative to the water/oil system. This paper documents the initial 6 years of the double-displacement project in the East Fault Block (EFB) of the Hawkins Field Unit, confirming the viability of the double-displacement recovery mechanism. It describes how early project performance indicated that oil gravity drainage was occurring slower than expected, the studies initiated to investigate the slower oil gravity drainage, and the successful outcome of those studies. In addition, the paper describes how the project has responded favorably to optimization efforts and gives a brief description of how results from the EFB have been applied to a proposed expansion to the West Fault Block (WFB).
Reserves Determination Using Type-Curve Matching and EMB Methods in the Medicine Hat Shallow Gas Field
Authors: West S. L. , Cochrane P. J. R.
Published: December 2007

Tight, shallow gas reservoirs in the Western Canada basin present a number of unique challenges in determining reserves accurately. Traditional methods such as decline analysis and material balance are inaccurate owing to the formation's low permeabilities and poor pressure data. The low permeabilities cause long transient periods that are not separated easily from production decline with conventional decline analysis, resulting in lower confidence in selecting the appropriate decline characteristics (exponential or harmonic), which effects recovery factors and remaining reserves significantly. Limited, poor-quality pressure data and commingled production from the three producing zones results in nonrepresentative pressure data and hence inaccurate material-balance analysis. This paper presents two new methods of reserve evaluation that address the problems described above for tight, shallow gas in the Medicine Hat field. The first method applies type-curve matching, which combines the analytical pressure solutions of the diffusivity equation (transient) with the empirical decline equation. The second method is an extended material balance (EMB), which incorporates the gas deliverability theory to allow selection of appropriate p/z derivatives without relying on pressure data. Excellent results were obtained when these two methods were applied to 10 properties that gather gas from 2300 wells. The two independent techniques resulted in similar production forecasts and reserves, confirming their validity. They proved to be valuable, practical tools in overcoming the various challenges of tight, shallow gas and in improving the accuracy in gas-reserves determination in the Medicine Hat field.
Tracer-Test Interpretation in Naturally Fractured Reservoirs
Authors: Ramírez-S. Jetzabeth , Samaniego-V. Fernando , Rodríguez Fernando , Rivera-R. Jesus
Published: December 2007

This paper presents a solution for the inverse problem, or interpretation, of the radial flow of tracers in naturally fractured reservoirs. Our model considers cubic-matrix-block fracture geometry, and by using the Rosenbrock method for nonlinear regression, we can estimate up to six parameters for this cubic-block geometry. We carefully tested the nonlinear regression against synthetical tracer-concentration responses affected by random noise with the objective of simulating, as closely as possible, step-injection field data. Results were obtained within 95% confidence limits. We also investigate sensitivity of the inverse-tracer-problem solution on the main parameters that describe this flow problem. The main features of the nonlinear regression program used in this study are also discussed. The procedure can be applied to interpret tracer tests in naturally fractured reservoirs, allowing the estimation of fracture and matrix parameters of practical interest (longitudinal-fracture dispersivity, a, matrix porosity, ϕ2, fracture half-width, W, matrix block size, d, matrix-diffusion coefficient, D2, and the adsorption constant, kd). This work's method offers a practical alternative for tracer-flow-test interpretation.
Viscometric Principles of Onsets of Colloidal Asphaltene Flocculation in Paraffinic Oils and Asphaltene Micellization in Aromatics
Authors: Escobedo Joel , Mansoori G. A.
Published: December 2007

Recently, we proposed a new technique for the determination of the onset of asphaltene flocculation.1 This new method is based on viscosity measurements of a crude oil upon titration with a precipitating solvent (e.g. n-pentane, n-heptane, etc.). The onset of asphaltene flocculation is detected by a sharp increase in the relative viscosity of the suspension in which asphaltene particle aggregation occurs. The key point in this development is the phenomenon of asphaltene flocculation induced by the addition of an n-paraffin hydrocarbon to a crude oil. The proposed method can also be applied to detect the onset of micellization of asphaltenes in aromatic solvents.

In this paper, we validate the proposed new technique from a theoretical standpoint.
Tailoring Hydrocarbon Streams for Asphaltene Removal
Authors: Del Bianco Alberto , Stroppa Fabrizio , Bertero Luigi
Published: December 2007

Oilfield production is often hindered by asphaltene precipitation which tends to fill the pores of reservoir rocks and plug the wellbore tubing and other auxiliary equipment used during crude-oil recovery.

Several remedies to remove these deposits have been proposed and patented, but the injection of aromatic solvents such as toluene and light petroleum distillates is normally preferred. Previous studies with a number of pure aromatic hydrocarbons have shown that the solvent capacity of these molecules may be very different and that the degree of condensation plays an important role. In this regard, tetralins and naphthalenes are superior to alkylbenzenes. However, because the use of pure compounds is not economically feasible, we examined various industrial streams and correlated their chemical composition to the solvent capacity. This work allowed the identification of the pseudocomponents whose relative concentration is crucial for evaluating the solvent performances. On the basis of these data, we were able to find new products with ideal characteristics. The efficiency of one of these products was confirmed by the analysis of the data obtained when using this new solvent to remove asphaltene in damaged wells of an Italian field.
Evaluation of Rock/Fracture Interaction: During Steam Injection Through Vertical Hydraulic Fractures
Authors: Kovscek A. R. , Johnston R. M. , Patzek T. W.
Published: December 2007

The design, results, and analysis of a steamdrive pilot in the South Belridge diatomite, Kern County, California, are reviewed. Pilot results demonstrate that steam can be injected across a 1,000-ft-tall diatomite column using hydraulically fractured wells and that significant oil is produced in response to steaming. A computationally simple numerical model is proposed and used to analyze reservoir heating and volumetric sweep by steam. Results from the analysis show that hydraulic fractures undergoing steam injection can be dynamic and asymmetrical.
Horizontal Well Testing of Isolated Segments
Authors: Frick T. P. , Brand C. W. , Schlager B. , Economides M. J.
Published: December 2007

A horizontal well test in a large reservoir and with small wellbore storage should produce certain distinct flow regimes. These should lead to the estimation of three permeabilities (along, normal and vertical to the well trajectory) the total well skin effect and, perhaps, the effective (open) well length. The objective of this work is to optimize well test design to obtain the desired flow regimes. It is shown that the important early-time flow regimes can be masked by wellbore storage effects. Therefore, afterflow should be minimized by using downhole shut-in. The storage effects can be estimated with empirical equations. These relationships also mark the beginning of the first interprétable flow regime. It is shown that for very thin formations or in situations where the well is drilled close to the top or bottom boundaries the early radial flow regime may not be seen at all. The length of an almost fully laterally penetrating horizontal well may also distort the late-time radial flow. In both of these instances, calculation of the controlling permeabilities becomes difficult to impossible. It may thus be desirable to test smaller segments of the well. Placing an observation gauge in an isolated segment during the flow testing of another segment can provide further information. It is shown that the derivative of the pressure response in the observation gauge exhibits a characteristic hump. When the hump appears, the permeability along the well axis can be calculated. Testing of isolated segments would also deliver a detailed picture of the skin distribution along an extended horizontal well. From such a test valuable information for enhanced stimulation and selective well completion design can be drawn.
Why Our Reserves Definitions Don't Work Anymore
Authors: Caldwell R. H. , Heather D. I.
Published: December 2007

Our current set of SPE reserves definitions, and their Security & Exchange Commission (SEC) counterparts, give a very misleading evaluation in a volatile pricing environment when dealing with mature, long life properties. Previous attempts to tighten the definitions through the use of "snapshot" price assumptions have had the opposite effect and have corrupted the technical uncertainty aspects of the definitions.

Probabilistic handling of pricing data allows evaluations to be performed that quantify economic uncertainty, thus removing the need for snapshot price assumptions or for a price forecast at all. The interaction between technical and economic uncertainties in reserves evaluation is discussed in the light of these results and the concept of a reference price for reserves evaluations is introduced.
Underbalance Criteria for Minimum Perforation Damage
Authors: Behrmann L. A.
Published: December 2007

A simple viscous drag force equation has been applied to single-shot laboratory perforation/flow experimental data to obtain perforation damage skin vs. underbalance. The equations are applicable for oil wells in consolidated, nonsanding formations and are a function of reservoir porosity, permeability, and diameter of the perforation tunnel in the rock.

The equations are independent of oil compressibility and viscosity. The dependency on perforation diameter suggests that larger charges are more damaging than small charges and that big hole charges are more damaging than equal-size deep penetrating charges. The equations can be used to calculate an optimum underbalance or a single-shot perforation skin for less than optimum underbalance. The single-shot skin can be used in well-flow analysis simulators to obtain a well perforation skin.
Multizone Subsea Completions in the Dai Hung Field, Vietnam
Authors: Lay K. R.
Published: December 2007

The early production phase of the Dai Hung field development resulted in the drilling and completion of five subsea wells. Because of the complex nature of the reservoirs, selective multizone completions were installed for effective reservoir data acquisition and reservoir management. The downhole completion designs used equipment that was primarily of existing proven design and downhole equipment installation was successfully achieved in a single trip. Ongoing reservoir management will be aided by the use of a subsea wireline system to facilitate data acquisition.
Well Testing for Radially Heterogeneous Reservoirs Under Single and Multiphase Flow Conditions
Authors: Thompson L. G. , Reynolds A. C.
Published: December 2007

In this work, we examine the behavior of pressure-transient data for single and multiphase flow in radially heterogeneous reservoirs. To illustrate multiphase flow behavior in these systems, we focus on heterogeneous gas-condensate reservoirs; however, we also consider other multiphase flow problems. It is well known1 that in some instances, e.g., water injection/falloff in homogeneous reservoirs, pressure-transient data from buildup (or falloff) tests cannot be obtained by superposition of drawdown (injection) pressure responses. In fact, drawdown and buildup reflect properties in different regions of the reservoir. This behavior is common to most occurrences of multiphase reservoir flow and is exaggerated in the presence of radial heterogeneity. This theoretical work describes the information contained in transient pressure derivative data and explains the fundamental difference in behavior between multiphase drawdown and buildup pressure-transient data in radially heterogeneous reservoirs. We show that multiphase buildup data may be treated like single-phase buildup data, but drawdown data is most indicative of properties in that region of the reservoir where mobility is changing most rapidly with time.
Application of Neural Networks to Modeling Fluid Contacts in Prudhoe Bay
Authors: Panda Manmath N. , Zaucha David E. , Perez Godofredo , Chopra Anil K.
Published: December 2007

Modeling the dynamic behavior of fluid movement in an oil reservoir is complicated because of non-linear interactions between reservoir heterogeneity and fluid flow. Simple regression, geostatistical, and numerical simulation techniques have been used in the past to model fluid movement with various degrees of success. Most of these methods, however, suffer from common drawbacks that they are time consuming and difficult to automate. This paper presents a new method based on artificial neural networks (ANNs) to model dynamic gas-oil contacts in the Prudhoe Bay reservoir. This method is fast, efficient, and highly automated and requires minimum user intervention.

The proposed method uses oil, gas, and water production, perforation history, permeability, sand and shale distribution, and surveillance data at surrounding wells as ANN input to predict the fluid distribution a t a target well. A two-step method is developed to design an ANN. The first step trains the network using previously measured data as input and output, and thus establishing the internal rules of the network. The second step uses the trained network to estimate the fluid distribution at target wells. Results show that the ANN method can predict fluid distribution at target wells more accurately and consistently than conventional methods.
Selection and Installation of CRA-Clad Flowlines in the Madden Deep Unit
Authors: Craig B. D. , Eckroth J. J.
Published: December 2007

This paper describes the selection and installation of corrosion-resistant-alloy (CRA)-clad flowlines and solid Alloy 625 piping wellhead tie-ins for hookup of wells in the Madden Deep Unit of Wyoming. The highly corrosive nature of the gas, coupled with the anticipated production of elemental sulfur and the close proximity to populated areas, dictated the use of these specialty materials. The special fabrication and installation requirements for CRA-clad flowlines, including some of the difficulties, are presented.
Scale Up of Heterogeneous Three Dimensional Reservoir Descriptions
Authors: Durlofsky L. J. , Behrens R. A. , Jones R. C. , Bernath A.
Published: December 2007

A general method for the scale up of highly detailed, heterogeneous, three dimensional reservoir descriptions is developed and applied. The method entails the nonuniform coarsening of the original detailed description, with finer resolution introduced in regions of potentially high flow rate (as identified through computationally efficient single phase flow calculations) and coarser, homogenized property descriptions applied throughout the bulk of the model. The method is applied to the simulation of three actual reservoirs and is demonstrated to provide coarsened reservoir models which give simulation results in close agreement with those of the original fine scale description but at considerable computational savings (speedups of nearly two orders of magnitude). In addition, it is shown that the method can provide geologically realistic coarse scale reservoir descriptions, which can be subsequently history matched to field data via geologically sensible modifications.
Modeling Gas-Condensate Well Deliverability
Authors: Fevang Øivind , Whitson C. H.
Published: December 2007

This paper gives an accurate method for modeling the deliverability of gas-condensate wells. Well deliverability is calculated with a modified form of the Evinger-Muskat1 pseudopressure (originally proposed for solution-gas-drive oil wells). The producing gas/oil ratio (GOR) is needed to calculate pseudopressure, together with pressure/volume/temperature (PVT) properties (black-oil or compositional), and gas/oil relative permeabilities. The proposed method is successfully tested for radial, vertically fractured, and horizontal wells.

Using the proposed deliverability model, we show that fine-grid single-well simulations can be reproduced almost exactly with a simple rate equation that uses pseudopressure. The key is knowing the producing GOR accurately. The effect of near-wellbore damage, vertical fracture, or flow improvement caused by horizontal well trajectory is readily incorporated into the rate equation as a constant skin term.

The effect of gas/oil relative permeability is studied. We show that well deliverability impairment resulting from near-wellbore condensate "blockage" is dependent only on relative permeabilities within the range defined by 1 <krg/kro < 50. Usually this represents gas and oil relative permeabilities ranging from 0.05 to 0.3. Gas relative permeabilities at low oil saturations (krg > 0.3) affect deliverability only for richer gas condensates.

A key observation and conclusion from this study is that critical oil saturation has no direct effect on well deliverability. We also show that interfacial tension (IFT) dependence of relative permeability has little or no effect on gas-condensate well performance (e.g., length of plateau production). The most important application of this study is to provide a simple method for calculating bottom-hole flowing pressure (BHFP) in coarse-grid models. We show that the proposed pseudopressure method is readily calculated for each well grid cell on the basis of only grid-cell pressure and saturation (i.e., producing GOR). Local grid refinement near wells is not necessary, and relatively large well grid cells can be used and still provide an accurate description of well deliverability.
Simulation of Linear Displacement Experiments on Massively Parallel Computers
Authors: Lee S. H. , Padmanabhan L. , Al-Sunaidi H. A.
Published: December 2007

We have developed a throat-bulb network model to simulate multiphase flow experiments. The model has been efficiently implemented on massively parallel computers (MasPar and CM5). This model has allowed us to study the dynamics of displacement processes. Using grids of size 64 × 64 × 128 (half a million cells), we are able to incorporate random variations in the throat and pore size distributions and observe flow patterns such as viscous fingering, stable front displacement, and invasion percolation. Furthermore, we are able to discern certain scaling rules in terms of macroscale variables.

Displacement processes in a network model with random distribution of throat and pore size can be characterized by three parameters: M (viscosity ratio), Ca (capillary number), and Cg (the ratio of capillary number and Bond number). Macroscale variables, Kr and Sor, are strongly dependent on flow patterns, whereas the dynamic capillary pressure, Pc, is independent of flow patterns.

Analysis of laboratory measurements of these macroscopic variables is generally based on steady state approximations and moreover, it offers no clue as to how one might extrapolate the results to the reservoir scale. Using the pore network simulator, we can model dynamic flow behavior and understand the scaling rules for experimental measurements. The simulator will eventually become a practical tool to investigate multi-phase flow in various flow conditions. Furthermore, a better understanding of experimental measurements will help us construct effective grid-block properties for reservoir simulation.
Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition
Authors: Zhang Xiaoyun , Morrow Norman R. , Ma Shouxiang
Published: December 2007

Spontaneous imbibition is of critical importance to oil recovery from fractured reservoirs. A widely used approach to predict oil recovery involves scale-up of laboratory results to reservoir conditions. Scaling involves the effects of sample size, shape, boundary conditions, viscosity and viscosity ratios, interfacial tension (IFT), pore structure, wettability, capillary pressure, and relative permeability. This work addresses the application of a characteristic length to scaling the combined effects of sample shape and boundary conditions with only minor variations in other parameters except for liquid/liquid (L/L) viscosity ratios.

Imbibition measurements are presented for cylindrical Berea sandstone cores of different lengths. For some experiments, core surfaces were partially sealed with epoxy to give different boundary conditions. Cores were initially saturated with refined mineral oils of different viscosities. A synthetic reservoir brine was used as the wetting phase. The characteristic length is defined as a function of bulk volume, areas of surfaces open to imbibition, and the distances from these surfaces to their respective no-flow boundaries. The characteristic length, in combination with a term that compensates for the effect of L/L viscosity ratio, gave close correlation of all data.
Dependence of Waterflood Remaining Oil Saturation on Relative Permeability, Capillary Pressure, and Reservoir Parameters in Mixed-Wet Turbidite Sands
Authors: Hirasaki G. J.
Published: December 2007

The dependence of waterflood oil recovery on relative permeability, capillary pressure, and reservoir parameters was investigated by numerical simulation. The relative permeability and capillary pressure curves were based on laboratory measurements on unconsolidated sands. The "water-wet" case is based on the assumption that the system is water-wet and measurements were made with refined oil. The "mixed-wet" case assumed that the system is mixed-wet and restored-state measurements were made with crude oil. The reservoir model was a prototype turbidite sand with a range of thickness and permeability values. The economic oil recovery was based on an economic limit water cut of 50%.

The remaining oil saturation (ROS) in the swept region for the water-wet cases was close to the residual oil saturation. The ROS of the mixed-wet cases ranged from low values near the residual oil saturation to far above the residual oil saturation. It is dependent on the reservoir parameters that govern (1) the vertical "film surface drainage" of oil by gravity, (2) accumulation of a high oil saturation and thus a high relative permeability under the caprock, and (3) updip migration of the oil that accumulated under the caprock. The dependence on the reservoir parameters can be summarized by dimensionless groups. There is a dimensionless time for the vertical displacement of oil by gravity. The accumulation of a high oil saturation under the caprock is dependent on the ratio of the capillary transition zone and the sand thickness. The updip migration is dependent on a combination of the gravity number and the endpoint mobility ratio.
Well-Completion Audits To Evaluate Gravel-Packing Procedures
Authors: McLeod H. O. , Pashen M. A.
Published: December 2007

Data collected during gravel-packed completions may be analyzed to evaluate the impact of specific completion practices on well performance. Operations in which gathering data is critical are during the initial flow and perforation cleanup after underbalanced perforating; during prescribed injection tests before gravel packing; during periods in which fluid is being injected into the formation (pre-packing perforations, fluid loss after perforating, fluid loss after gravel packing); and during stabilized flow after the well is brought on line. This data can be used to calculate an approximate value for kh (md • ft) and an instantaneous completion efficiency at different stages of the completion. By comparing these instantaneous completion efficiencies, the damage contribution of certain operations and the damage-prevention aspects of other operations may be quantified. This methodology should provide a valuable resource to those pursuing continuous improvement in well-completion operations, particularly those involved in sand control.
Optimization of Balanced-Plug Cementing
Authors: Harestad Kristian , Herigstad T. P. , Torsvoll Arne , Nødland N. E. , Saasen Arild
Published: December 2007

Placing properly balanced cement plugs in wells has been a serious problem to the drilling industry for decades. The cement plug is rarely found at the desired depth. Because of the fact that the cement slurry usually is more dense than the well fluid, the cement plugs are found deeper than anticipated, and the quality of the cement plug further down may be doubtful. This often results in setting a new cement plug to proceed with operations such as kickoff in the wellbore, abandonment, or pulling the blowout preventer. In the North Sea area cement plugs fail in more than 25% of the cases. Several techniques have been developed to keep the cement in place, but they are either very time consuming or they have a low degree of success.

A tool has been developed that is deployed below the cement plug, preventing the cement slurry from escaping down the well. This tool is very easy to install, does not take extra rig time and covers all sizes of hole diameters, from 152.4 to 584.2 mm (6 to 23 in.), with one tool. Before field application, the system was tested in full scale, where cement plugs were set in casings both with and without the new tool. The result from this testing showed that the new tool had a very high degree of efficiency compared to the reference tests that were performed without the tool. This paper presents the results from the tests and case histories where the tool was used.