bluuebunny/crossref_metadata_2025 huggingface dataset:
Do Your Horizontal Wells Deliver Their Expected Rates?
Authors: Levitan M. M. , Clay P. L. , Gilchrist J. M.
Published: December 2007

This paper presents the results of comprehensive analysis of BP horizontal-well productivity and completion performance data. The study was performed to benchmark the performance of existing horizontal wells with a view to developing simple, empirical techniques that could be used for predicting the performance of future wells. The developed correlation predicts a range of expected well productivities for future wells. This prediction reflects limitations in current completion technology and possible reservoir heterogeneities. The analysis method is based on presenting the existing well-productivity data in the form of dimensionless parameters—the well-productivity coefficient and the normalized productivity improvement factor (PIF). The results of this study can be used to:

Sense check the theoretical well-performance estimate for undeveloped discoveries with the historical performance for similar reservoirs. Provide quality control for newly commissioned wells to see if performance is as expected. Help optimize development well design (i.e., high-angle vs. conventional) for reservoir exploitation. Offer a means to rank well-surveillance work based on what the initial well performance is with respect to global historic experience.
Integrated Geological and Petrophysical Characterization of Permian Shallow-Water Dolostone
Authors: Holtz Mark H. , Major R. P.
Published: December 2007

The complex interplay between depositional facies and diagenesis in dolostones makes calculating petrophysical properties from wireline logs challenging. Complex pore geometries and mineralogies control rock petrophysical properties. The complex mineralogy of some dolostone reservoirs, moreover, has profound effects on wireline-log measurements. Therefore, equations for calculating porosities and saturations must be tailored to specific pore-geometry/mineralogy combinations. If dolostone reservoirs are divided into petrophysical/mineralogical facies of similar depositional and diagenetic textures—and, thus, similar pore geometries and mineralogy—empirical equations that apply specifically to that geologically identified facies can be developed. These equations yield more accurate calculations of porosity and water saturation.

Our examples from Permian shallow-water dolostone reservoirs of the Permian Basin, southwestern United States, demonstrate analytical approaches for calculating petrophysical properties in these complex rocks. Four general petrophysical/mineralogical facies characterize Permian shallow-water dolostone reservoirs: (1) subtidal, mud-dominated dolostone; (2) subtidal, grain-dominated dolostone; (3) dolomitic and siliciclastic peritidal rocks; and (4) diagenetically altered, subtidal dolostone.
A Practical Method for Anticipating Asphaltene Problems
Authors: Wang J. X. , Buckley J. S. , Burke N. E. , Creek J. L.
Published: December 2007

Asphaltenes can separate from some oils during depressurization. In other cases, the addition of lift or injection gas can destabilize asphaltenes. This paper presents an integrated approach to predicting all these potential asphaltene problems. Laboratory characterization of asphaltene stability in stock-tank-oil samples is used in combination with standard pressure/volume/temperature (PVT) and compositional data. Details of the characterization technique and prediction method are provided for problems of practical interest, especially for offshore developments where advance planning is of particular importance for many flow-assurance problems. Predictions of asphaltene stability with this approach are compared with live-oil measurements and field experience, where available.
Fluid Flow in Various Patterns and Implications for EOR Pilot Flooding
Authors: Brigham William E.
Published: December 2007

Pilot testing of enhanced oil recovery (EOR) projects in the field is common, for such tests demonstrate the effectiveness of a particular EOR process. Nevertheless, separating the effects on recovery of pattern geometry, pattern size, and reservoir heterogeneities from the EOR process itself is nontrivial. This paper illustrates that geometric and geological factors are evaluated easily at unit mobility ratio. Subsequently, nonunit-mobility-ratio effects can then be predicted. In this fashion, the efficiency of the EOR process is decoupled from geometry and permeability variation.
Surface-Gravity Monitoring of the Gas Cap Water Injection Project, Prudhoe Bay, Alaska
Authors: Brady Jerry L. , Ferguson John F. , Seibert John E. , Chen Tianyou , Hare Jennifer L. , Aiken Carlos V. L. , Klopping Fred J. , Brown John M.
Published: December 2007

Modeling and field-test surveys indicate that time-differenced surface gravity can be used to successfully monitor the Gas Cap Water Injection (GCWI) Project at Prudhoe Bay, Alaska. Simulation results have shown that more than 95% of the injected water can be accounted for, including reasonable assumptions concerning the noise level in the measurements. The flood front can be reliably detected within 2,000 to 3,000 ft for the Prudhoe Bay reservoir that is buried at 8,200 to 8,800 ft true vertical depth (TVD).

The world's first 4D surface-gravity surveillance of a water-flood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the approved Gas Cap Water Injection Project (GCWI) at Prudhoe Bay. A major factor in the approval of the waterflood was to show that water movement could be monitored economically with a very limited number of wells. Conventional monitoring techniques would have been cost-prohibitive because of the requirement for drilling numerous new surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be detected with high-resolution surface-gravity measurements. Field tests at Prudhoe Bay have demonstrated that sufficiently accurate gravity data can be obtained.

This paper will discuss both inverse modeling of time-differenced gravity maps and four test surveys that have been completed to perfect the gravity-measurement technique. Forward and inverse gravity modeling were carried out on a suite of reservoir simulations of the GCWI. Differences in the gravity field with time reflect changes in the reservoir densities, which in turn reflect pore-fluid content. A constrained least-squares method was used to invert synthetic gravity data for the subsurface density distribution. The modeling procedure has been formulated to allow testing for sensitivity to gravity-sampling patterns, noise, and various constraints on model parameters such as density, total mass, and moment of inertia.

These simulation results have shown that more than 95% of the injected water can be accounted for in the inverse model. These estimates include reasonable assumptions concerning the noise level in the measurements of both the gravity data and the location data using the Global Positioning System (GPS). The average flood front can be reliably detected within 2,000 to 3,000 ft for the Prudhoe Bay reservoir that is buried at 8,200 to 8,800 ft TVD. Time-differenced surface-gravity and GPS data were gathered over the Arctic Ocean in typical winter conditions (−40°F) accurately enough to monitor the waterflood (gravity =±10 μGal and GPS = ±1 cm elevation; a μGal is approximately one-billionth of the Earth's normal gravity).
Uncertainty Assessment of Well-Placement Optimization
Authors: Güyagüler Baris , Horne Roland N.
Published: December 2007

Determining the best location for new wells is a complex problem that depends on reservoir and fluid properties, well and surface-equipment specifications, and economic criteria. Numerical simulation is often the most appropriate tool to evaluate the feasibility of well configurations. However, because the data used to establish numerical models have uncertainty, so do the model forecasts. The uncertainties in the model reflect themselves in the uncertainties of the outcomes of well-configuration decisions.

We never possess the true and deterministic information about the reservoir, but we may have geostatistical realizations of the truth constructed from the information available. An approach that can translate the uncertainty in the data to uncertainty in the well-placement decision in terms of monetary value was developed in this study. The uncertainties associated with well placement were addressed within the utility-theory framework using numerical simulation as the evaluation tool. The methodology was evaluated by use of the Production forecasting with UNcertainty Quantification (PUNQ)-S3 model, which is a standard test case that was based on a real field. Experiments were carried out on 23 history-matched realizations, and a truth case was also available. The results were verified by comparison to exhaustive simulations. Utility theory not only offered the framework to quantify the influence of uncertainties in the reservoir description in terms of monetary value, but it also provided the tools to quantify the otherwise arbitrary notion of the risk attitude of the decision maker. A hybrid genetic algorithm (HGA) was used for optimization.

In addition, a computationally cheaper alternative was also investigated. The well-placement problem was formulated as the optimization of a random function. The genetic algorithm (GA) was used as the optimization tool. Each time a well configuration was to be evaluated, a different realization of the reservoir properties was selected randomly from the set of realizations, all of which honored the geologic and dynamic data available from the reservoir. Numerical simulation was then carried out with this randomly selected realization to calculate the objective function value. This approach has the potential to incorporate the risk attitudes of the decision maker and was observed to be approximate but computationally feasible.
Analysis and Prediction of Microseismicity Induced by Hydraulic Fracturing
Authors: Warpinski N. R. , Wolhart S. L. , Wright C. A.
Published: December 2007

This paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Along with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid-saturated reservoirs experience much more widespread activity than do gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture, because considerable microseismic activity occurs around the tip as it propagates.
New Developments in Aerated Mud Hydraulics for Horizontal Well Drilling
Authors: Sunthankar A. A. , Miska S. , Kuru E. , Kamp A.
Published: December 2007

Drilling using aerated muds offers a major advantage in controlling mud effective density, enabling both underbalanced and balanced drilling. However, planning of aerated mud drilling operations is difficult because of complex hydrodynamics of aerated mud flow, resulting in a lack of confidence in predicting and controlling operational variables. It is, therefore, necessary to better understand the hydraulics of aerated mud flows in order to be able to accurately calculate bottomhole pressure and optimal flow rates for drilling.

Pressure losses are a strong function of gas-liquid flow patterns. The existing methods of predicting flow patterns are based on an extrapolation of results from pipe flow to flow in annuli. Therefore, to verify the applicability of this existing practice, the present study focuses on hydraulics of aerated fluids through a large-scale annulus.

Extensive experiments were performed in a unique field-scale low-pressure flow loop (8×4.5 in., 90 feet long) in horizontal position with and without drillpipe rotation. The liquids used were water and aqueous polymer solution (CMC+XCD+water) at flow rates in the range of 75 to 360 gpm and air in the range of 10 to 1000 scfm. Measurements of pressure drop and average liquid holdup over the entire annular section were carried out. To our knowledge, no such data have been published before.

It was observed that intermittent flow was present for most of the cases, which is contradictory to some existing field and simulation practices that assume homogeneous gas-liquid flow. Also, the flow pattern boundaries are shifted as compared to pipe flow, which necessitates the modification of flow transition criteria.

Higher frictional pressure drop was observed in case of flow with drillpipe rotation. Also, a higher frictional pressure drop was found in case of air-non-Newtonian fluid flow as compared to air-water flow. The results of this study show that two-phase pipe flow models, when modified and applied to two-phase flow in annuli, considerably underpredict pressure drop occurring during the two-phase flow in annuli.
Use of Prior Information in Gradient-Based History Matching
Authors: Brun Bertrand , Barker John W. , Gosselin Olivier
Published: December 2007

This paper demonstrates how certain geological constraints can be imposed during gradient-based history matching by use of a prior term in the objective function. We extend an existing method of parameter selection (gradzone analysis) to the case in which the prior covariance matrix is nondiagonal. We show that the parameter selection can be made independently of the weight assigned to the prior information, and illustrate how the shape of the gradzones is modified to reflect the correlation structure of the porosity or permeability fields. Finally, the use of the prior term to preserve a relationship between porosity and permeability during the historymatching process is demonstrated.
Permanent Fiber-Optic Monitoring at Northstar: Pressure/Temperature System and Data Overview
Authors: Kragas Tor K. , Turnbull Bill F. , Francis Michael J.
Published: December 2007

In-well fiber-optic sensing systems offer the potential for continuous, highly accurate, highly reliable, real-time data measurements. During the past 3 years, permanent downhole fiber-optic pressure and temperature (P/T) transducers have become an accepted new technology in the oil and gas industry. Northstar, on the North Slope of Alaska, represents the first multiwell, new field development to incorporate fiber-optic P/T gauges. Real-time downhole pressure data are critical to managing the miscible-gas injection enhanced-recovery process at Northstar. Fiber-optic gauges were selected because of their reliability at high temperatures and their ability survive the severe shock and vibration conditions associated with post-installation perforating operations. As of publication, optical P/T gauges have been installed in 15 wells at North-star. The data have proved valuable to the asset team in monitoring the perforating program, determining initial reservoir pressure, managing well drawdown, diagnosing completion problems, building wellbore-hydraulics and inflow-performance models, and providing pressure-buildup data, all without the need for well interventions and the resulting loss in production volume.
Effect of Low Frequency Percussion in Drilling Hard Rock
Authors: Topanelian E.
Published: December 2007

Introduction

In the development of a fluid-operated hammer drill for accelerated penetration of hard rock formations in oil wells, a research investigation was conducted to evaluate the percussion effects obtained with different design characteristics and to determine the possibilities of percussion in the low frequency range. Tests were conducted on granite blocks and comparable impact forces were measured with a load cell under selected test conditions. These full-scale laboratory tests provided an evaluation of the effectiveness of percussion which was further supported by actual downhole field performance.

While much pertinent data have been presented by other investigators the method of evaluation described in this article resulted in good correlation between laboratory and field performance and may be applicable in other low frequency percussion developments.

Experimental Method

For these tests the bit was held stationary and the test block was rotated and forced upward against the bit by a hydraulically-lifted rotary table. "Weight on bit" was calculated from pressure readings on the fluid system of the lifting cylinders-corrected for tare and friction. Percussion was obtained with several tubular hammers of different weights up to 320 lb. These were lifted mechanically and allowed to drop by gravity from various heights onto a slidably-mounted bit sub or "floating anvil" for calibration of the load cell response with known kinetic energy of the hammers. During evaluation of percussion effects, the hammers were hydraulically operated to provide a range of percussion frequencies up to 1,020 blows per minute delivered to the anvil.

To obtain comparable test readings, the load cell of the strain gauge type, was attached to the bottom of the anvil or bit sub in place of the bit. The load cell rested on a typical granite test block mounted on the drilling table. The latter was hydraulically supported as in the actual drilling operation. The effect of support resistance was the same for all tools when calibrating. Impact forces so determined were thus directly comparable with one another for the purposes of this investigation.
Combining Gradual Deformation and Upscaling Techniques for Direct Conditioning of Fine-Scale Reservoir Models to Interference Test Data
Authors: Mezghani Mokhlès , Roggero Frédéric
Published: December 2007

Reconciling multiscale data for reservoir characterization is a crucial issue, because different data types provide different information about the reservoir architecture and heterogeneity. It is essential that reservoir models preserve small-scale property variations observed in well logs and core measurements and capture the large-scale structure and continuity observed in global measures such as well-test and production data.

In this paper, we present a new methodology to directly update fine-scale geostatistically-based reservoir models by combining gradual deformation parameterization for the fine-scale geostatistical model, and an upscaling technique for the coarse-scale flow simulation model. As consequence, both fine- and coarse-scale models are updated by dynamic data during the history matching process.

The proposed methodology includes:

Perturbation of the fine-scale geostatistical model using the gradual deformation parameterization. Gradual deformation ensures the preservation of the overall geostatistical properties of the fine model. Generation of the coarse-scale flow simulation model by upscaling the fine-scale geostatistical model. Fluid-flow simulation and sensitivity computation of the flow simulation results with respect to the fine-scale parameterization. This sensitivity computation is analytical and takes into account the upscaling process. Direct updating of the fine-scale geostatistical model using classical optimization process. Direct updating ensures consistency between the fine- and coarse-scale models.

The accuracy of the proposed methodology was improved by calibrating the flow simulation model. The objective of this calibration is to reduce the error introduced by the upscaling step during the flow simulation.

We applied successfully our methodology for fine-scale reservoir characterization process by integrating permanent downhole gauge measurements directly into a 3D-geostatistical model containing about two million gridblocks.

This test is designed to highlight several key issues of the proposed methodology:

Efficiency of the upscaling step, coupled with gradient-based optimization to speed up history matching. Usefulness of the calibration step for a correct integration of upscaling techniques in history matching. Capability of the methodology for maintaining consistency and coherency between fine-scale and coarse-scale models. Improvement of the reservoir characterization process by integrating dynamic data at both fine geostatistical scale and coarse simulation scale.
Buckling of Tubulars Inside Wellbores: A Review on Recent Theoretical and Experimental Works
Authors: Cunha J. C.
Published: December 2007

The buckling behavior of tubulars inside wellbores is the subject of many articles. This paper presents a general overview on most of the literature available on the subject and also comments on the different, and sometimes conflicting, solutions presented in various works.

Different aspects of the phenomenon are discussed, including sinusoidal (lateral) and helical buckling and the influence of torque.
Openhole Expandable-Sand-Screen Completions in Brunei
Authors: Lau Hon Chung , Vliet Jacques van , Ward Mike , Morin David , Djamil Arifun , Kuhnert Paul , Aldaz Walter , Shanks Steven
Published: December 2007

Expandable sand screens were deployed successfully as a sand-control device in two horizontal openhole completions in two geologically different offshore fields in Brunei. A critical success factor was the choice of a drill-in fluid (DIF) that maintained hole stability and gave a near-gauge hole while running and expanding the sand screen. Field experience and extensive research led to the choice of a synthetic-based DIF for one well but a water-based one for the other. Challenges unique to the deployment of expandable sand screens in these wells are discussed.
New Rheological Correlations for Guar Foam Fluids
Authors: Khade Sudhakar D. , Shah Subhash N.
Published: December 2007

Foams provide a highly attractive alternative to conventional non-Newtonian fluids for various oil and gas applications because of their high viscosity and low liquid content. Foams have a long history of proven performance in well stimulations, drilling, acidizing, cleanout operations, and enhanced oil recovery (EOR). Foam apparent viscosity is used in hydraulic (pressure drop) calculations for various pumping operations. Thus, accurate rheological characterization is very important to predict foam viscosity.

In this investigation, rheological experiments are carried out with guar gel and guar foam fluids with a ½-in.-pipe viscometer at 1,000 psi and temperatures ranging from 100 to 200°F. Guar, surfactant, and nitrogen (N2) are used as the gelling agent, foaming agent, and gas phase, respectively. Formulations were prepared and tested at several flow rates for qualities ranging from 0 to 80%.

This study has shown that both guar gel and guar foam fluids exhibit behavior analogous to the power-law model fluid. The experimental data are used to develop new rheological correlations to predict power-law fluid-flow parameters and, thus, the apparent viscosity of the foam fluids. These new correlations are functions of temperature, foam quality, shear rate, and fluid concentrations and were compared with various published correlations. The available correlations in the literature have assumed that the foam's flow behavior index is similar to that of the liquid phase. This assumption does not support the basic physics that the increase in viscosity decreases the flow behavior index. Our results show that the previous assumption is invalid and leads to a prediction of extremely low apparent viscosity for foam fluids. In contrast to previous studies, we report high apparent viscosities of high-quality foam fluids.
Multiple-Phase Generation During Carbon Dioxide Flooding
Authors: Henry Richard L. , Metcalfe Robert S.
Published: December 2007

This paper describes research to determine the pressure and temperature region in which multiple phases are generated for selected reservoir oils displaced by CO2. The major purposes of this study were (1) to determine whether single-contact PVT conditions and multiple-contact flow generated multiple phases over equivalent pressures and temperatures, and (2) to determine whether multiple-phase generation would affect mobility.

Multiple phases were generated for two reservoir oils of similar composition above the CO2 minimum miscibility pressures (MMP's) for temperatures between 307.5 and 322 K. For a limited temperature range, the pressures over which these multiple phases were observed agreed fairly well with those determined in single-contact PVT cell studies. However, multiple phases were also seen at higher temperatures in the multiple-contact displacements.

Pressure-drop data as a function of CO2 injection volume were obtained for displacements within the multiple-phase region and for displacements conducted at pressures above the multiple-phase region. Comparison of these data indicates that multiple-phase generation reduces mobility within the flow system used. Mobility reduction would be beneficial during application of CO2 flooding on a reservoir scale.
The Effect of Several Polymers on the Phase Behavior of Micellar Fluids
Authors: Pope Gary A. , Tsaur Kerming , Schechter Robert S. , Wang Ben
Published: December 2007

We made static measurements of the phase volumes of mixtures of surfactant, polymer, alcohol, water, oil, sodium chloride, and in some cases polymer additives. We also made a limited number of viscosity, phase concentration, and interfacial tension (IFT) measurements. The purpose was to determine systematically the effect of various polymers on the phase behavior of various surfactant formulations. We made measurements with and without oil (n-octane and n-octane/benzene mixtures) across a range of salinity appropriate to the particular surfactant at temperatures between 24 and 75°C.
Accurate Subgrid Models for Two-Phase Flow in Heterogeneous Reservoirs
Authors: Efendiev Yalchin R. , Durlofsky Louis J.
Published: December 2007

Subgrid effects can have a strong influence on flow and transport in oil reservoirs. In this work, a new model for the representation of subgrid terms is introduced and applied to two-phase reservoir flows. The model entails a generalized convection-diffusion treatment of the saturation equation as well as an extended representation for total mobility in the pressure equation. Motivation for the form of the model is provided through a consideration of volume averaging and homogenization results. The numerical computation of the subgrid terms and the implementation of the overall method are described. The accuracy of the new subgrid representation is compared to that of coarse-scale models with no subgrid treatment and to coarse models based on pseudorelative permeabilities. The new model consistently provides more accurate overall coarse-scale predictions, relative to reference fine-scale results, than the other coarse-scale models, particularly in cases when the global boundary conditions vary in time.
Surface Chemistry of Oil Recovery From Fractured, Oil-Wet, Carbonate Formations
Authors: Hirasaki George , Zhang Danhua Leslie
Published: December 2007

Oil recovery by waterflooding in fractured formations is often dependent on spontaneous imbibition. However, spontaneous imbibition is often insignificant in oil-wet, carbonate rocks. Sodium carbonate and anionic surfactant solutions are evaluated for enhancing oil recovery by spontaneous imbibition from oil-wet carbonate rocks. Crude-oil samples must be free of surface-active contaminants to be representative of the reservoir. Calcite, which is normally positively charged, can be made negative with sodium carbonate. The ease of wettability alteration is a function of the aging time and temperature and the surfactant formulation.
Compaction-Induced Porosity/Permeability Reduction in Sandstone Reservoirs: Data and Model for Elasticity-Dominated Deformation
Authors: Schutjens P. M. T. M. , Hanssen T. H. , Hettema M. H. H. , Merour J. , de Bree P. , Coremans J. W. A. , Helliesen G.
Published: December 2007

Open literature and new experimental compaction data from five reservoir and 16 outcrop sandstones are used to delineate the near-elastic, inelastic, and failure domains in 3D-stress space for porosity classes of 5 to 15%, 15 to 25%, and 25 to 35%. Applications of this compaction-domain model include the analysis of the extent of the near-elastic domain (where elasticity theory can be used to describe and predict rock deformation), the pore-volume compressibility (Cpp), and the permeability reduction as a function of reservoir stress path. This is illustrated for a well-consolidated sandstone reservoir with an average porosity of approximately 18%. Two aspects of dynamic reservoir modeling in the near-elastic domain are addressed: calculation of Cpp from raw volumetric-compaction data as a function of isotropic total stress change, and the correction of Cpp for a nonhydrostatic reservoir stress path. Open-literature work combined with our experimental data indicates that the compaction-induced permeability reduction of 15 to 25% porosity sandstone in the near-elastic domain depends predominantly on the increase of the effective mean stress, not on the reservoir stress path.
Numerical Simulation and Sensitivity Analysis of Gravity-Assisted Tertiary Gas-Injection Processes
Authors: Ren W. , Cunha L. B. , Bentsen R.
Published: December 2007

Corefloods and field investigations confirm that a large amount of incremental tertiary oil can be recovered from dipping waterdrive reservoirs using gravity-assisted tertiary gas-injection processes. These processes include the double-displacement process (DDP) and the second-contact water-displacement (SCWD) process. The DDP consists of injecting gas into waterflooded oil zones. The SCWD process consists of submitting these gasflooded zones to a new water-displacement process.

Reservoir simulations performed with an adaptive-implicit simulator were applied to investigate the macroscopic mechanisms of the two processes. The effects of several important parameters on the performance of the DDP were studied to optimize the oil production of the process. Moreover, the SCWD process was simulated to investigate its feasibility.

The results show that both processes are efficient methods for recovering the residual oil to water. A good representation of the laboratory results was obtained through the simulations. It was confirmed that oil-film flow plays a very important role in achieving high recovery efficiencies in the DDP. In the SCWD process, trapped gas reduces the possibility of the residual oil being trapped in the center of pores in the secondary water invasion. Consequently, residual oil can be recovered quickly by a second water-flood. Therefore, the SCWD process is suitable for application in situations in which the source of gas is not sufficient, and where the formation has a high irreducible gas saturation.
Identifying Reservoir Compartmentalization and Flow Barriers From Primary Production Using Streamline Diffusive Time of Flight
Authors: He Zhong , Parikh Harshal , Datta-Gupta Akhil , Perez Jorge , Pham Tai
Published: December 2007

We propose a novel approach that uses streamline-based drainage-volume computations using a "diffusive time of flight" to infer reservoir compartmentalization during primary production. Our approach consists of three steps. First, we perform a traditional decline-type-curve analysis of the primary production data to identify well communications and estimate the drainage volume of individual wells. Second, starting with a geological model, the drainage volumes of each well are recomputed with a streamline-based flow simulation. Finally, flow barriers and reservoir compartmentalization are inferred through a matching of the streamline-based drainage volumes with those from the decline-curve analysis.

Our approach is completely general and can be applied to reservoirs in the early stages of field development and with very few wells. We demonstrate the power and utility of our proposed method using synthetic and field examples. The field example is from a field in the Gulf of Mexico. Starting with a reservoir model based on well-log and seismic data, reservoir compartmentalization and flow barriers are identified from 3 years of primary production response.
Modeling of Both Near-Wellbore Damage and Natural Cleanup of Horizontal Wells Drilled With Water-Based Drilling Fluids
Authors: Ding Y. , Longeron D. , Renard G. , Audibert A.
Published: December 2007

Prediction of formation damage that occurs in horizontal wells, often openhole completed, is a critical point for optimizing an oilfield development. The economic impact of near-wellbore induced drilling damage and cleanup efficiency has led to significant progress in both experimental and numerical studies designed to assess the wellbore flow properties during oil production.

In a previous paper, a methodology combining both experimental and numerical approaches was presented to evaluate the natural cleanup of horizontal wells drilled with an oil-based mud (OBM). This paper presents an extension of the methodology for simulating both (a) near-wellbore invasion and permeability damage generated with a water-based mud (WBM), and (b) natural cleanup during oil backflow when the well is put into production. There is a fundamental difference between WBM and OBM invasions. In an oil-bearing formation, the displacement of the oil in place with an OBM filtrate is a miscible displacement process, while the displacement with a WBM filtrate is a two-phase flow process (imbibition), generating high wetting-phase saturation in the invaded zone. Then, during oil backflow, a portion of the wetting phase is trapped, leading to residual wetting-phase saturation greater than the initial one. Even in the absence of chemical interaction between filtrate and fluids in place, this induces an adverse water/oil relative permeability effect, which is an additional permeability impairment.

This paper describes a numerical approach to model the formation damage with WBM and to predict well performance for natural cleanup when the well is subject to a pressure drawdown. The kinetics of fluid filtrate invasion, the filter-cake properties, and the filtrate/oil relative permeability curves in imbibition and drainage, together with damaged and return permeabilities, are obtained from specific drilling fluid damage laboratory tests. Using these data, the fluid filtrate invasion during the drilling phase is simulated, leading to a cone-type invasion depth along the horizontal well. This approach has allowed us to study the impact of various parameters related to fluids or cake properties, drilling conditions, and natural cleanup processes on the well performance.
Optimal Injection Strategies for Foam IOR
Authors: Shan D. , Rossen W. R.
Published: December 2007

Miscible-gas foam field trials have employed a variety of injection strategies, with mixed results. Using simulation, we compare foam-injection strategies in homogeneous reservoirs with a variety of foam models. The optimal injection strategy for overcoming gravity override with foam in a homogeneous reservoir is alternating injection of separate, large slugs of gas and liquid at fixed, maximum-allowable injection pressure. This strategy minimizes both gravity override and time of injection, with minimal rise in injection-well pressure. Injection of gas at maximum pressure can partially reverse the effects of gravity slumping of surfactant during injection of liquid. The process is remarkably insensitive to the detailed properties of the foam, as long as foam does not collapse abruptly and completely at a "limiting water saturation" Sw*. However, care is needed to exclude the effects of numerical artifacts in simulating such a process, especially if foam collapses abruptly and completely at Sw*.

An idealized model for the process reveals the mechanisms responsible for process success, why injection at fixed injection pressure is better than injection at fixed rate, why details of foam behavior play a secondary role in sweep efficiency, and why numerical artifacts can be difficult to identify.
A Case Study in the Design and Execution of Subsea Production Development Wells in the Captain Field
Authors: Rae G. , Hampson J. , Hiscox I. , Rennie M. , Morrison A. , Ramsay D.
Published: December 2007

This paper outlines the challenges presented and the solutions chosen in executing the subsea-production-well construction design for the Captain Area B subsea development (see Fig. 1). It gives an overview of how a blend of proven and emerging technologies can be applied to develop such fields in innovative ways to meet performance metrices.
Insights Into Upscaling Using 3D Streamlines
Authors: Chawathé Adwait , Taggart Ian
Published: December 2007

Large, multimillion-cell geological models are frequently constructed in an effort to "capture" the vertical heterogeneity measured by well logs and the areal heterogeneity inferred by the depositional environments. These criteria often result in fine-scale models at a resolution of 0.1 to 0.3 m vertically and 30 to 100 m areally, resulting in reservoir models on the order of 107 grid cells. Recourse is made to upscaling to obtain coarsened but computationally efficient flow-simulation models. The coarsened models commonly result in no more than 1 to 5% of the original grid size, underscoring the need for judicious upscaling. Of greater importance is demonstrating, for the chosen grid dimensions, that the upscaled representation is both reasonable and optimal in the sense that a significantly better template would be difficult to obtain.

We consider two nonuniformly coarsened models to demonstrate the issues involved and show that the use of 3D streamline methods offers insightful alternatives to decoupled analysis for both the scaleup template design and the pre- and post-diagnostics. We confine ourselves to property-upscaling methods that use local grid information as opposed to estimating upscaled properties based on some global measure. For this class of problems, we demonstrate that the diagnostic phases are necessarily separate from the upgridding and upscaling processes.
Estimating Non-Darcy Flow Coefficient From Buildup-Test Data With Wellbore Storage
Authors: Spivey J. P. , Brown K. G. , Sawyer W. K. , Frantz J. H.
Published: December 2007

An algorithm has been developed for computing the pressure response for a well with constant wellbore storage and non-Darcy skin factor across the completion. The algorithm has been used to generate type curves for drawdown and buildup tests. The buildup-pressure-derivative response for a well with non-Darcy flow across the completion exhibits a much steeper slope during the transition out of wellbore storage than that of a well with constant skin.

No reservoir model with constant wellbore storage and skin can reproduce this steep derivative. Thus, if it is present in a buildup test, the well is experiencing either decreasing wellbore storage or decreasing skin factor, or both.

With the new type curves, under favorable conditions, both Darcy and non-Darcy skin components may be estimated from a single buildup test following constant-rate production. The new algorithm also may be used to model a test sequence comprising multiple flow and buildup periods.
Scalability of the Deterministic and Bayesian Approaches to Production-Data Integration Into Reservoir Models
Authors: Vega Leonardo , Rojas Danny , Datta-Gupta Akhil
Published: December 2007

Current techniques for production-data integration into reservoir models can be broadly grouped into two categories: deterministic and Bayesian. The deterministic approach relies on imposing parameter-smoothness constraints using spatial derivatives to ensure large-scale changes consistent with the low resolution of the production data. The Bayesian approach is based on prior estimates of model statistics such as parameter covariance and data errors and attempts to generate posterior models consistent with the static and dynamic data. Both approaches have been successful for field-scale applications, although the computational costs associated with the two methods can vary widely. To date, no systematic study has been carried out to examine the scaling properties and relative merits of the methods.

We systematically investigate the scaling of the computational costs for the deterministic and the Bayesian approaches for realistic field-scale applications. Our results indicate that the deterministic approach exhibits a linear increase in the CPU time with model size compared to a quadratic increase for the Bayesian approach. We also propose a fast and robust adaptation of the Bayesian formulation that preserves the statistical foundation of the Bayesian method and at the same time has a scaling property similar to that of the deterministic approach. We demonstrate the power and utility of our proposed method using synthetic examples and a field example from the Goldsmith field, a carbonate reservoir in west Texas.
Competing Roles of Interfacial Tension and Surfactant Equivalent Weight in the Development of a Chemical Flood
Authors: Enedy S. L. , Farouq Ali S. M. , Stahl C. D.
Published: December 2007

This investigation focused on developing an efficient chemical flooding process by use of dilute surfactant/polymer slugs. The competing roles of interfacial tension (IFT) and equivalent weight (EW) of the surfactant used, as well as the effect of different types of preflushes on tertiary oil recovery, were studied. Volume of residual oil recovered per gram of surfactant used was examined as a function of these variables and slug size.

Tertiary oil recovery increased with an increase in the dilute surfactant slug size and buffer viscosity. However, low IFT does not ensure high oil recovery. An increase in surfactant EW used actually can lead to a decrease in oil recovery. Tertiary oil recovery was also sensitive to preflush type. Reasons for the observed behavior are examined in relation to the surfactant properties as well as to adsorption and retention.
New Iterative Coupling Between a Reservoir Simulator and a Geomechanics Module
Authors: Tran David , Nghiem Long , Settari Antonin
Published: December 2007

Interactions of solid mechanics and fluid flow have been studied by numerous researchers for the past several years. Different methods of coupling such as full and iterative coupling have been used. Nevertheless, the accuracy and the large run time of the coupled solid-mechanics fluid-flow model are outstanding issues that prevent the application of the coupled model in full-field studies. In this work, a novel relationship of porosity as a function of pressure, temperature, and mean total stress is developed for iterative coupling of stress and flow. The new formula not only improves the accuracy of the coupling but also reduces substantially the number of coupling iterations. The latter feature decreases significantly the CPU time. The new approach was implemented in a modular, iteratively coupled system. The rapid convergence provides the equivalent of a fully coupled method that is necessary to investigate complex coupled problems. The main advantage of this type of coupling is that a geomechanics module can be easily coupled with different reservoir simulators. The paper gives some comparisons of results obtained by the new porosity formula with another formulation.
Pressure/Pressure Convolution Analysis of Multiprobe and Packer-Probe Wireline Formation Tester Data
Authors: Onur Mustafa , Hegeman Peter S. , Kuchuk Fikri J.
Published: December 2007

In cases in which flow-rate data are not reliable, the need for flow rate in estimating permeability from wireline formation tester multiprobe and packer-probe pressure-data sets can be eliminated by the use of the so-called pressure/pressure (p/p) convolution. The p/p convolution is based on the use of different pressure-data sets recorded at two different spatial locations and thus enables one to perform parameter estimation without flow rate. In this work, we present a detailed analysis of multiprobe and packer-probe pressure-transient tests by considering various p/p convolution options for both single-layer and multilayer systems. Approximate equations that apply during spherical and radial flow for a vertical well in a single-layer system for various p/p convolution options are derived. These equations indicate which parameters can be determined uniquely from p/p convolution. It is shown that p/p convolution analysis sometimes may not provide unique parameter estimates. Also, we provide a flow-rate-estimation method that proves useful to check the validity of parameter estimates obtained from p/p convolution analysis. Two example tests, a synthetic multiprobe test and a field packer-probe test, are given to illustrate the methodology and procedures developed in this work.
An Analytical Scaling Method for Spontaneous Imbibition in Gas/Water/Rock Systems
Authors: Li Kewen , Horne Roland N.
Published: December 2007

A method was developed to scale the experimental data of spontaneous water imbibition (cocurrent) for gas/water/rock systems. In this method, a dimensionless time was defined with the effects of relative permeability, wettability, and gravity included. The definition was not empirical but based on a theoretical derivation. Using this dimensionless time, experimental data from spontaneous water imbibition in different rocks with different size, porosity, permeability, initial water saturation, interfacial tension, and wettability might be scaled. The scaling model proposed in this study for gas/water/rock systems was verified experimentally for different rocks (Berea, chalk, and graywacke from The Geysers) with significantly different properties; it was also verified experimentally at different initial water saturations in the same rock. The scaling results from this study demonstrated that the cocurrent spontaneous water imbibition in gas/water/rock systems could be scaled and predicted.
Quantification of Displacement Mechanisms in Multicomponent Gasfloods
Authors: Johns R. T. , Yuan H. , Dindoruk B.
Published: December 2007

Local displacement efficiency in gasfloods depends strongly on the minimum miscibility pressure (MMP) or minimum miscibility enrichment (MME). The values for these design parameters depend in turn on the displacement mechanisms: vaporizing, condensing, or a combination of the two known as a condensing/vaporizing (CV) drive. Characterization of the displacement mechanism, however, is currently limited to these broad categories, with little reference to the degree to which a CV displacement is condensing or vaporizing. This "discrete" classification approach can result in significant confusion in the interpretation and comparison of various miscible gasfloods. The focus of this paper, therefore, is to present a method to quantify in a continuous way the fraction of a multicomponent gasflood that is vaporizing or condensing as the pressure or gas enrichment is increased.

The approach relies on finding key tie lines for a dispersionfree 1D displacement using method of characteristic theory (MOC). We quantify the displacement mechanism for any number of oil or gas components by calculating the displacement path lengths along ruled surfaces bounded by these key tie lines. We show how to determine the displacement mechanism along each of these ruled surfaces by the calculation and comparison of the key tie-line lengths. Several multicomponent fluid characterizations are considered, including a 12-component enriched-gasflood and a 13-component CO2 flood.

The results show that as the pressure or enrichment is increased, condensation occurs at the expense of vaporization. We also show by numerical simulations that the sensitivity of the local displacement efficiency to dispersion depends on the condensing fraction of the displacement. We show that the trends in displacement efficiency sensitivity to dispersion oppose previously published results, which showed that vaporizing displacements are more sensitive to dispersion than condensing ones. The differing trends are likely the result of improper and discrete determination of the displacement mechanism.