bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Optimization using Multiphase Well Testing: A Case Study from East Kalimantan, Indonesia
Authors: Retnanto Albertus , Weimer Ben , Kontha I Nyoman Hari , Triongko Heru , Azim Azriz , Kyaw Htun Aung 
Published: December 2007

Abstract
A multiphase flow meter named PhaseTester has been developed for determining oil, water, and gas production rates simultaneously. This new approach of well testing delivers significantly improved data quality and availability, allowing quick well performance trend analysis and immediate well diagnosis. Rapid, accurate production diagnosis allows timely decisions without prior well information or standard rate stabilization periods resulting in shorter, more reliable well tests stored in an easily accessible, user-friendly database.
The PhaseTester provides a comparatively lighter operation unit and reduces risk of human error resulting in improved safety. Compared to conventional units, the physical size of the PhaseTester is usually half the size and the extensive pressure lines and safety devices are reduced. The meter is environment friendly since all the well effluents are returned to the production flowline without the need for separation or burning of hydrocarbons during the test.
Obtaining periodic, accurate well test measurements is the key factor in Vico Indonesia Indonesia's well production optimization. The PhaseTester was introduced to monitor and optimize the production performance for gas lift wells. Changes in well performance were observed immediately allowing the operations engineer to quickly analyze the production characteristics and make decisions based on true accurate real time test data. Selected case histories demonstrate the results of these tests.
Multiple Factors That Influence Wireline Formation Tester Pressure Measurements And Fluid Contacts Estimates
Authors: Proett Mark A. , Chin Wilson C. , Manohar Mohan , Sigal Richard , Wu Jianghui 
Published: December 2007

Abstract
Pressure measurements using conventional wireline formation testers (WFTs) can be influenced by near-wellbore effects such as mudcake buildup and filtrate invasion, which are coupled physical events. These combined effects can change the interpretation of the pressure data, shifting the gradient curves and the fluid contact depths.
Recent papers have discussed corrections for wettability and for capillary pressure effects on formation tester measurements, the next steps needed for improved predictive measurements.1,2,3 Suggestions by different investigators have stimulated interest in several research directions. Because the foregoing effects are the result of mud filtrate invasion, which normally involves multiphase flow, it is necessary to quantify all competing results using a numerical simulator that models all effects rigorously. The work described in this paper models the complete process quantitatively with an invasion simulator that includes the dynamically coupled effects of mudcake growth and multiphase, immiscible filtrate invasion.
The simulator is used to model the invasion profile, that is, the changing oil-water ratio while pumping. It includes wettability and capillary pressure effects. Many of the parameters predicted in the simulation can be crosschecked from log data, including mobility estimates from WFTs and fluid saturations from NMR and array induction logs. Modern WFTs such as the Reservoir Description Tool (RDT) can monitor the fluid properties while pumping.4 This information can, in turn, be used to determine the volume fractions of the produced fluids. The same simulator used for invasion is used to match pump-out results and determine supercharge (i.e., elevated pressures near the wellbore) and capillary pressure effects.
Several field examples are used to illustrate how these methods are combined to correct pressure measurements, gradients, and fluid contacts.
Deconvolution of Well Test Data as a Nonlinear Total Least Squares Problem
Authors: von Schroeter Thomas , Hollaender Florian , Gringarten Alain C. 
Published: December 2007

Abstract
Finding a good algorithm for the deconvolution of pressure and flow rate data is one of the long-standing problems in well test analysis. In this paper we give a survey of methods which have been suggested in the past 40 years, and develop a new formulation in terms of the logarithm of the response function. The main advantage of this nonlinear encoding over prior methods is that it does not require explicit sign constraints. Moreover we introduce a new error model which accounts for errors in both pressure and rate data; here the rates can be cumulative or continously measured.
In this formulation, deconvolution is equivalent to a separable nonlinear Total Least Squares problem for which standard algorithms exist. Preliminary numerical results with both simulated and field data suggest that the method is capable of producing smooth, interpretable reservoir response estimates from data contaminated with errors of up to 10% in rates, provided a careful choice of weight and regularization parameters is made.
Interference Testing with Horizontal Observation Wells
Authors: Al-Khamis M. , Ozkan E. , Raghavan R. 
Published: December 2007

AbstractInterference and pulse tests at horizontal wells introduce features and issues that require specific procedures for evaluation and analysis. In addition to reservoir properties, it becomes necessary to account for three-dimensional pressure distributions, as horizontal wells tend to be rather long. The objective of this paper is to discuss the effect of the existence of a horizontal observation well on the analysis of interference tests.We use a semi-analytical model for interference testing with a horizontal observation well. The conductivity of the horizontal wells may be infinite or finite. We discuss the flow regimes in the observation well. The effect of anisotropy is shown to significantly affect the interference between two horizontal wells.In many practical situations, it becomes necessary to evaluate such tests by numerical means. At this time, no simple method exists to calibrate observation well responses computed by numerical simulators. The results of this study should provide for an accurate measure of pressure responses to calibrate numerical simulators.
Transient Pressure Response of Fluvial Reservoir With Branching Channel and Splay
Authors: Zhao Gang , Thompson Leslie G. 
Published: December 2007

AbstractFluvial reservoirs with branching channels and splays comprise a commonly encountered depositional system, however, characterization of this type of system using transient pressure analysis has not yet been fully explored. This article presents a semi-analytical method to compute the transient pressure and pressure response for this system type. It simplifies the computation by decoupling the complex-geometry system into a discrete set of simple-geometry systems that are in hydraulic contact with each other, and exchange fluids at their hydraulic contacts[1,2]. The computed pressure and pressure derivatives were compared with those of other simple well/reservoir systems to gain insight into the information contained in the responses. The source and sink method[3] was used to compute the pressure response in the Laplace domain and the results were inverted numerically using the Stehfest Inversion algorithm[4]. The discussion in this paper is focused on four cases, consisting of a main channel and a side branch that connects with the main branch at angles of 30, 45, 60 and 90 degrees, respectively. In each of these cases, the set of "image" wells that create no-flow boundaries is easy to generate, and an efficient computational algorithm is developed. Excellent pressure and pressure derivative responses have been obtained; detailed examination of these responses provides insight into methods that may aid in the identification and characterization of this type of system.
Evaluation of the Effects of Heterogeneity, Grid Refinement, and Capillary Pressure on Recovery for Miscible-Gas Injection Processes
Authors: Solano Reinel , Lee Sheng-Tai , Ballin Paulo R. , Moulds Tim P. 
Published: December 2007

Abstract
Large grid blocks, usually required to perform field scale reservoir simulations, introduce artificial numerical dispersion that may lessen the effect of other dispersion mechanisms like diffusion, dispersive mixing, or capillary pressure. The effect of diffusion and dispersive mixing on recovery in miscible gas injection may be approximated by numerical dispersion. Capillary pressure effect, instead, should be explicitly evaluated.
Previous works performed at BP have shown discrepancies about the effect of capillary pressure on recovery for miscible gas displacements. The discrepancies seem strongly related with the particular permeability distribution and injection conditions used to perform the evaluation. Therefore, this project attempts to evaluate simultaneously the effects of heterogeneity, capillary pressure and grid refinement on recovery.
The simulated process consisted of WAG injection of an enriched gas in a stochastic 2-dimensional cross-section. The results show that capillary pressure increased oil recovery when Lorenz Coefficient (LC) was less than 0.5 and reduced oil recovery for very heterogeneous reservoirs, LC greater than 0.6. Oil recovery decreased significantly with increasing heterogeneity when LC was greater than 0.4. Grid refinements performed in the horizontal direction had a minor impact on oil recovery; on the other hand, the impact of vertical grid refinement depends on specific conditions of capillary pressure and heterogeneity.
The results demonstrate the importance of capillary pressure in the reservoir model for miscible-gas displacements. In addition, this work gives some guidelines to estimate when capillary pressure has greater impact.
General Productivity Models for Wells in Homogeneous and Layered Reservoirs
Authors: Larsen Leif 
Published: December 2007

Abstract
The need for simple models to estimate the productivity of arbitrary wells in homogeneous and layered reservoirs should be obvious. The current paper addresses this problem by extending current analytic methods to handle a greater variety of well configurations. One of the more important extensions covers deviated wells with limited flow entry through a fairly simple summation scheme. Another being the treatment of wells with a limited height fracture.
Two basic drainage shapes are included in the models: Circular and other regular drainage shapes with the well clearly inside the drainage area, and rectangular without any restriction on well length and location for homogeneous and commingled layered reservoirs, but with the well required to lie clerly inside the drainage area for crossflow systems. For highly deviated wells the rectangular models are based on the approach of Goode and Kuchuk1 for horizontal wells, with the difference between the deviated well and a horizontal well handled through a modified skin value. Fractures of limited height are also based on Ref. 1 by adding an appropriate skin value.
Handling Production-Data Uncertainty in History Matching: The Meren Reservoir Case Study
Authors: Kabir C. S. , Young N. J. 
Published: December 2007

Abstract
History matching reservoir performance ordinarily implies adjusting geologic and rock-fluid flow properties until a satisfactory match is attained between the observed and model response. Property adjustments inevitably imply a trial-anderror approach.
Regardless of the approach used in any study, we presuppose the integrity of observed data. Unfortunately, measurements of gas and water do not have the desired precision when oil is the primary fluid of interest. For instance, when gas is flared, the quality of metering suffers. In some operations, withdrawal of small samples of a three-phase mixture near the wellhead becomes the sole basis for establishing water content in a production stream. These practices often introduce large uncertainty in reported data of all three phases.
This paper explores how we dealt with some of these issues while attempting to match 30-year performance in the Meren field in offshore Nigeria. Results show that production data, affected by wellbore mechanical problems, can be diagnosed using log-log type curve. Furthermore, this work shows that discerning watercut from wellhead samples is prone to errors, and issues with wellbore flow calibration can lead to large uncertainties in performance prediction.
Assessment of Uncertainty Assessment Methods
Authors: Liu Ning , Betancourt S. , Oliver D. S. 
Published: December 2007

Abstract
Uncertainty in future reservoir performance is usually evaluated from the simulated performance of a small number of reservoir models. Unfortunately, most of the methods for generating reservoir models conditional to production data are known to create a distribution of realizations that is only approximately correct. The adequacy of the approximations is unknown, although several previous investigations of the approximate algorithms have suggested that the distributions of realizations could be badly misleading. In this paper, we evaluate the ability of the various sampling methods to correctly assess the uncertainty in reservoir predictions by comparing the distribution of realizations with a standard distribution from a Markov chain Monte Carlo method.
This study compares the ensemble of realizations from five sampling algorithms for a synthetic, one-dimensional, single-phase flow problem, in order to establish the best algorithm under controlled conditions. The small test problem was chosen in order that a large enough number of realizations could be generated from each method to ensure the statistical validity of the comparisons. Five thousand realizations were generated from each of the approximate sampling algorithms. The approximate sampling methods evaluated were linearization about the maximum a posteriori model (the square-root of the covariance matrix method), randomized maximum likelihood, and two two pilot point methods with six and nine pilot points locations. Realizations were also generated by a Markov chain Monte Carlo method with local perturbations and an attempt was made to generate realizations from a rejection sampling algorithm. The distributions of realizations from the approximate methods were compared to the distributions from the exact, methods. While the approximate sampling methods performed relatively well for evaluating uncertainty in average reservoir porosity and effective steady-state permeability, most failed to adequately assess uncertainty in some other function of the reservoir model such as the distribution of extreme permeability values or the data mismatch. In general, the method of randomized maximum likelihood performed better than other approximate methods.
History Matching Using a Streamline-Based Approach and Exact Sensitivity Coefficients
Authors: Gautier Y. , Noetinger B. , Roggero F. 
Published: December 2007

Abstract
Geostatistical models provide detailed geostatistical images of the reservoir containing several millions of gridblocks. Reservoir engineers often have to deal with history matching problems: they have to find images that honor production data. This is often time consuming due to the large number of numerical simulations that often have to be run.
Optimization coupled with gradient-based methods enables to efficiently find a reservoir representation that respects all static and dynamic data. Nevertheless, for multiphase flow or for compositional problems, only relatively small models can be handled with a finite volume flow simulator.
Streamline-based simulation provides accurate and fast estimates to various flow problems. Simulations can also be performed on large fine grid geological model. Recently, streamline-based simulation has been used for inversion problems. Analytical gradients of production data with respect to a geostatistical parametrization have been computed for the tracer flow case. This approach can not take into account changes in boundary conditions or multiphase flow. In this paper, we will derive the gradients for two-phase flow problems without any assumption concerning the boundary conditions. The gradients will then be used in an optimization loop for a synthetic history matching problem.
Applied Multisource Pressure Data Integration for Dynamic Reservoir Characterization, Reservoir, and Production Management: A Case History from the Siri Field, Offshore Denmark
Authors: Borch Carsten 
Published: December 2007

Abstract
The Siri Field offshore Denmark is a small Paleocene sandstone reservoir. The field has a low structural relief and a thin undersaturated oil column with a bottom aquifer. The formation consists of firm, fine to very fine-grained, cross-bedded to massive sandstone with abundant glauconite reflecting deposition by deep marine turbidity currents. The sandstone is interbedded with several types of non-reservoir facies, including frequent carbonate cemented intervals forming rather persistent lateral layers. Inverted 3D seismic identify intra reservoir acoustic impedance features indicating possible extensive reservoir heterogeneities which impact fluid flow, reservoir drainage and flooding patterns.
Reservoir simulation studies prior to field development sanctioning revealed that the recovery factor was very sensitive to the level of fluid transmissibility across the major acoustic impedance features. Although these transmissibilities could not be confidently estimated a priori to development sanctioning, having a fully compartmentalized reservoir was considered highly unlikely.
The Siri Field is currently developed with five long horizontal oil producers and two simultaneous water and gas (SWAG) injectors. Reservoir pressure information acquired during concurrent early stage development well drilling and production proved valuable during the interactive interdisciplinary detailed planning of subsequent development well trajectories and completion intervals.
Pressure sources integrated to provide reservoir scale dynamic formation characterization and to aid in the day to day reservoir- and production management comprise: Openhole formation testsDrill stem test"Advanced" cased hole formation tests (applying coiled tubing conveyed dual select firing heads)Permanent downhole pressure gaugesTractor conveyed production logging
This paper describes, how this multitude of pressure surveillance data have been integrated to evaluate and document: Field wide pressure communicationReservoir scale permeabilitiesCross flow severity associated with large dynamic pressure gradients along extended horizontal production wells
Furthermore, the information value from permanent downhole gauges is addressed.
Meeting the Challenge to Extend Success at the Pikes Peak Steam Project to Areas with Bottom Water
Authors: Wong F. Y. F. , Anderson D. B. , O'Rourke J. C. , Rea H. Q. , Scheidt K. A. 
Published: December 2007

Abstract
This paper provides a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation (CSS) and steam drive in non-bottom water. To test development over relatively thin bottom water (less than 5 meters), various steam processes were field trialed. Field pilot results from vertical well CSS, dual horizontal well gravity drainage, and a combination of vertical injectors-horizontal well producer are presented for comparison.
Based on field experience and numerical simulation input, CSS has been successfully conducted with economic steam-oil ratios (SOR) in areas with up to 4 meters of bottom water by injecting significantly larger steam slugs in what is termed a drive, block and drain process. In thicker bottom water, the ability to operate at constant pressure to prevent bottom water influx confers an advantage to the horizontal well approach. Followup field scale developments of some bottom water areas are described. Numerical simulation results indicate that pressuring up of a depleted steamflooded zone to be an optimum strategy for maximizing offset flank recovery. This is being implemented in the field by re-injecting produced vent gases.
PVT Properties and Viscosity Correlations for Gulf of Mexico Oils
Authors: Dindoruk Birol , Christman Peter G. 
Published: December 2007

ABSTRACT
New empirical PVT correlations for Gulf of Mexico (GOM) oils have been developed as a function of commonly available field data. Correlations have been developed for: bubblepoint pressure,solution gas oil ratio at bubblepoint pressure,oil formation volume factor at bubblepoint pressure,undersaturated isothermal oil compressibility,
Oil Viscosity: dead oil viscosity,saturated oil viscosity, andundersaturated oil viscosity.
For the development of correlations, we have covered a wide range of data. More than one hundred pressure-volume-temperature (PVT) reports from GOM have been used in the development of correlations. Two of the published correlations, Standing, and Petrosky and Farshad correlations were tested using our GOM data set. Proposed correlations of this study predicted the PVT properties of GOM oils better than the correlations published in the literature, even when the coefficients of the published correlations are tuned. Using the correlations of this study, we have written a simple program that can generate PVT datasets for use in reservoir simulation. Laboratory measured differential liberation data for two different oil samples were also compared against our empirically generated differential liberation data.
Screenless Tip-Screenout Fracturing: A Detailed Examination of Recent Experience
Authors: Fan Y. , Looney M. D. , Jones J. A. 
Published: December 2007

Abstract
Texaco has been conducting screenless tip-screenout fracture to stimulate production in the Kern River field of California. During 1998–2000, more than 500 fracture treatments were pumped in some 200 wells. These treatments caused average oil production to nearly triple. This paper documents the results of the tip-screenout fracture treatments conducted over the past three years and presents a statistical analysis to determine how the production response is related to the treatment parameters. The goal was to identify the conditions that on average lead to the optimum production response.