bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation of Super-K Behavior in Ghawar by a Multi-Million Cell Parallel Simulator
Authors: Dogru Ali H. , Dreiman William T. , Hemanthkumar Kesavalu , Fung Larry S. 
Published: December 2007

Abstract
This paper describes an application of a Massively Parallel Reservoir Simulator for a Giant Carbonate Reservoir with faults, fracture and Super-K zones. It is shown that by using a multi million cell description, premature water breakthrough and complex reservoir behavior is captured with minimum up scaling of the original geological description. The new technology used in this work provides significant reduction in simulation model construction and history matching time.
Super-K is a well-known phenomenon in parts of Ghawar where it provides extremely large conductivity to fluid flow. These formations are comprised of vugs, faults, fractures and stratiform dolomite rocks. They form effective flow conduits for water and impact the overall sweep. For the proper accounting of complex heterogeneities, a portion of the reservoir was simulated using a 2.5 million-cell reservoir simulation model. The fault map from the 3-D seismic was incorporated; a thin layer described stratiform Super-K layers with 70 Darcy permeability. A dual porosity type grid was imposed to handle the high permeability conduits. The fine grid in the area of interest was gradually coarsened for the proper accounting of boundary fluxes.
This model with over 50 years of history and about 800 wells, was run using Saudi Aramco’s parallel simulator, POWERS1. The total execution time was 4 hours. Premature water breakthrough in the middle of the reservoir was matched closely. The phenomenon of water movement in the vertical direction was duplicated as observed in the field. This study has shown that the ability to handle extreme heterogeneities leads to a more realistic history match. State of the Art technologies enable engineers to build, execute and complete the history match in a few months.
Improved Oil Recovery by New Horizontalization Strategy in Giant Carbonate Reservoir
Authors: Salameh Lutfi A. 
Published: December 2007

Abstract
This paper presents the merits and demerits of the multilateral horizontal applications in a giant Middle Eastern carbonate reservoir. It also discusses the main achievement of a new optimized development strategy to improve oil production, control waterfronts, and maximizing the optimum oil recovery.
Difficulties encountered from the current multilateral horizontalization (MLH) policy are also discussed, including the impact on oil production, water evolution, sweep efficiency, cost and the optimum oil recovery.
Results obtained from the detailed full field simulation study will be addressed for proper assessment of the performance of the current development plan and other recommended alternative optimum schemes for short and long terms of the field development.
The simulation study concludes that the use of horizontal wells single or multi lateral holes is critical and directly impacts the oil production. Areal and vertical balance / imbalance vertical sweep efficiencies are also effected by alleviating water movement and enhancing well productivity or injectivity.
A new optimized horizontalaization strategy was recommended based on the results of this study. The new policy has been implemented successfully in 16 producers during 1999. Initial assessment of the performance of these wells indicates an exceptional success in terms of increasing oil production and deferring water breakthrough as a result of improving vertical sweep efficiency.
Comprehensive Solutions for Transient-Flow Problems in 3D Homogeneous Domains
Authors: Rahman N. M. Anisur , Bentsen Ramon G. 
Published: December 2007

Abstract
In the petroleum engineering literature, analytical solutions have always been treated as benchmarks for many complicated situations in reservoirs. But efforts to develop analytical solutions for some transient-flow problems have been hindered seriously due to a lack of appropriate mathematical tools. However, this study demonstrates that the use of an integral-transform technique (ITT) results in the comprehensive development of analytical solutions for transient-flow problems subject to three-dimensional (3D) flow in a cylindrical coordinate system. This approach presents the solutions in the time and space domains. Variable production rates and all possible combinations of the boundary conditions are also considered in the formulation. Time-dependent rates and boundary conditions are dealt with directly, avoiding the use of the principle of superposition or Duhamel’s theorem.
Lessons learned from Wireline Formation Testing with Single and Multiple Probes
Authors: Su H. J. , Al-Anezi K. G. , Sinha S. P. , Ceyhan A. G. 
Published: December 2007

Abstract
Previously there were few RFT data available for the Wara formation of the Greater Burgan field. Therefore, during recent drilling, pressure measurements were made to investigate if vertical pressure equilibrium exists in the formation after a production history of more than fifty years. The erratic nature of measured pressure profiles indicates that vertical communication is poor in the reservoir.
In each of the pressure measurements, a single probe was inserted into the mud filtrate zone, and then about 20 cc of liquid was collected. In addition to obtaining the pressure value, we also derived the permeability value by diagnosing the pressure derivative signatures. Multiple probes were also used to evaluate vertical permeability over an interval of 2.3 feet. This paper describes how we analyze the data and overcome the problems encountered. We demonstrate that 3D-reservoir simulation of the formation test can improve the quality of data interpretation. A summary of the analytical method development is also given.
Due to the high precision, 0.01 psi, of the quartz gauge, the single-probe pressure derivative data quality was satisfactory for low permeability sands and the analytical method could derive both the horizontal and vertical permeability values successfully. However, for high permeability sands, there often existed a pressure hump immediately after shut-in and it resulted in unrecognizable signatures.
A non-linear regression method was used to interpret multiple-probe test data. However, sometimes a simultaneous pressure match for all the probes was difficult to achieve by the analytical model. 3D finite-difference simulation was required to fit the data and characterize the geological heterogeneity. Single-probe pre-test results were used to provide a good initial permeability guess for the numerical model. Gamma ray and formation image loggings were proven valuable to determine the layering of the numerical model. Finally, core measurement and buildip test results were compared with formation test results.
Novel Compact Oil/Water Separator Tested in Nimr
Authors: Nnabuihe Larry 
Published: December 2007

Abstract
A novel compact oil-water separation concept using 2 hydrocyclones in series with recycle has been proven through laboratory testing and Nimr wellhead trials.
The objective was to investigate the technical feasibility of using hydrocyclones at the wellhead to separate Nimr crudes prior to considering a downhole trial. With ‘light’ Nimr crude, good water separation efficiency was achieved with a residual OIW better than conventional separation. With more typical heavy viscous crude, similar separation efficiency was attained but OIW levels were significantly higher.
The technology provides a viable option for separation at the wellhead, for example prior to reinjection in water flood projects or where surface infrastructure is flow constrained. Reservoir benefits through improved pressure support or sweep could make the business case for downhole separation more favourable; however, it poses challenges to downhole monitoring and well architecture.
Investigation of Revaporization of Retrograde Condensate
Authors: Li Shi , Zheng Xitan , Dai Zhijian , Luo Kai , Chen Gang , Liu Ning 
Published: December 2007

Abstract
A series of experiments have been carried out in order to quantitatively investigate the revaporization efficiency of retrograde condensate by dry gas injection. The experiment includes three main parts: (1) gas injection below the dew point pressure in the PVT cell, (2) gas injection above and (3) below the dew point pressure in a long-core flooding apparatus. Instead of the simple synthetic fluid and the packed core systems usually used in the previous literature, an actual gas condensate fluid and an approximately one meter long-core were employed here. The tests with long-core apparatus show that more condensate above the dew point is recovered than below the dewpoint, forcefully justifying the traditional argument that the full pressure maintenance is superior to the partial pressure maintenance according to the condensate recovery. An interesting discovery is that dry gas can effectively revaporize not only the intermediate but also the heavy hydrocarbons (i.e., C20+), which is in contrary with the common belief that the heavy hydrocarbon cannot be revaporized by dry gas.
A New and Rigorous Equation for Modeling Gas Condensate Well Deliverability Including an Experimental Study of Revaporization of Retrograde Condensate
Authors: Xie Xingli , Luo Kai , Song Wenjie , Li Baozhu , Li Shi , Zheng Xitan 
Published: December 2007

AbstractAs the well flowing bottomhole pressure falls below the dew point, liquid dropout occurs in gas condensate reservoirs. Gas condensate well behavior is unique in a sense that it is characterized by severe loss of well deliverability. Thus well productivity and gas re-injection are two among the critical issues in development of many gas condensate reservoirs, particularly for the high condensate yield cases.Generally retrograde condensate is viewed immobile at reservoir conditions so that the standard dry gas flow equations based on flow-after-flow, isochronal and modified isochronal testing, etc., have frequently been used to analyze gas condensate well productivity. However, due to the combined effects of the bi-phase flow of gas and condensate near the wellbore and reduction in well deliverability caused by liquid buildup, this approach seems to be inadequate and usually leads to misleading results, suffering doubt and criticism up till now. Therefore, there is a need to develop a rigorous equation to express the thorough flow behavior of gas and condensate in porous media.Based on a detailed description of flow behavior in gas condensate pools, a definite solution problem is formulated. Subsequently the analytic solution is derived under pseudo-steady-state conditions. The derivation procedures are detailed. Finally a rigorous overall deliverability equation desired is obtained by incorporating the effect of non-darcy flow in the vicinity of well bore. Then the parametric calculation methods are discussed briefly. A calculation example using the new equation is compared with the result calculated by the standard dry gas productivity equation. The comparison shows that the standard binomial productivity equation usually used in the dry gas condition over-predicts the production potential of gas condensate well.Additionally, in order to investigate the quantitative efficiency of condensate revaporized by lean gas injection, the laboratory experiments of gas injection have been made in a PVT cell, and above and below the dew point in a long core apparatus. Comparison of the tests shows more recovery of condensate in longcore above the dewpoint is obtained than below the dewpoint, justifying the popular argument with regard to the condensate recovery that the full pressure maintenance is superior to the partial pressure maintenance. However, the full pressure maintenance in the high-pressure reservoirs may not be the best choice due to the expensive investments on equipment. A comprehensive cost evaluation is suggested, but this is out of the scope of the present study.
Estimation of Evaporated Oil for a Sixty Two Year Old Immiscible Gas Injection Project
Authors: Al-Mahroos Faisal M. , Kumar K. 
Published: December 2007

Abstract
This paper presents a novel approach to estimate the recovery of oil by the stripping of the lighter components by the injection gas, using the fluid characterization models derived with semi-continuous thermodynamics method in earlier studies.
Bahrain Field is an asymmetrical anticline trending in the North - South direction. The sedimentary column extends from Cambrian Saq sandstone to the Miocene reefal deposits exposed on the surface. The field contains twenty-two reservoirs with the hydrocarbon content varying from tarry oil in Aruma to dry gas in Khuff reservoirs. The geology of the field is extremely complex with a large number of faults occurring in the Wasia group formations, which contain the major oil reservoir of Bahrain field, the Mauddud reservoir. The field was discovered in 1932 and gas injection in the under saturated Mauddud reservoir was initiated in 1938. Over the years of injection a secondary gas cap has developed. The dominant recovery mechanism is gravity drainage with crestal injection of gas from the Khuff zones. The reservoir being heterogeneous and structure complex with a large number of faults, most of the injected gas gets produced.
In addition to the above recovery mechanism, stripping of the lighter components in the oil by the "dry" injection gas, is significant. In fact the associated gas produced is enriched with the stripped oil and forms the major feed stock for the LPG recovery plant. To understand the recovery mechanisms and to provide fluid characterization for the simulation work in progress, characterization of the reservoir and injection fluids were carried out in earlier studies. These fluid models were validated with the available experimental data satisfactorily. This paper describes how these fluid representations were used along with the production and the compositional data of the associated gas produced, to simulate the gas injection process. Also with the current strategy of development of the field, future oil recoveries expected from the stripping process have been estimated.
Integrated Study of a Fractured Middle East Reservoir with Stratiform Super-K Intervals – Part 2: Upscaling and Dual Media Simulation
Authors: Cosentino L. , Coury Y. , Daniel J. M. , Manceau E. , Ravenne C. , Van Lingen P. , Cole J. , Sengul M. 
Published: December 2007

Abstract
The paper describes the upscaling and reservoir simulation of a giant Middle East oilfield, whose geological modeling is described in a companion paper (1). The main objective of the study was the simulation of the irregular water advance observed in some parts of the field, as a consequence of peripheral water injection.
Three scales of heterogeneity were identified in the characterization phase, namely the matrix, the stratiform Super-K intervals and the fractures. To accommodate the different hydraulic properties of each heterogeneity system, a dual-media approach (dual porosity and dual permeability) was used.
The assignment of the effective properties to the simulation grids (matrix and fracture grids) was performed independently for the three heterogeneity systems. In particular, the geostatistical facies model was upscaled using algebraic methods, while the stratiform Super-K layers and fractures properties were explicitly reproduced at the simulation gridblock scale, through an original upscaling procedure.
The history match was achieved in a short time, by a small variation of the fractal dimension of the fracture distribution and without resorting to any local modification.
Simulation results showed that the fracture system was the controlling factor in terms of water advance and breakthrough, while the impact of the stratiform Super-K layers proved to be of second order.
In a later stage, the model was utilized to run production forecasts under different exploitation scenarios.
Conclusions of this study indicate that for such porous and fractured reservoirs with stratiform Super-K occurrences, a detailed characterization of all the heterogeneity systems, coupled with a dual-media formulation, are necessary requisites for accurate reservoir simulation and effective reservoir management.
Selecting Perforation Intervals and Stimulation Technique in the Khuff Reservoir for Improved and Economic Gas Recovery
Authors: Zillur Rahim , Al-Qahtani Mohammed Y. 
Published: December 2007

Abstract
Saudi ARAMCO has initiated an acid fracturing program to treat the carbonates of the Khuff reservoir in the Ghawar field in the eastern province of Saudi Arabia. Khuff reservoir belongs to the Permian age and is encountered at an average depth of about 11,500 ft. Two main producing intervals of this reservoir, Khuff B and Khuff C, have tested high quantity of condensate rich gas.
Khuff reservoir consists mainly of dolomite and limestone sections with streaks of shale and anhydrite that constitute the non-permeable and possible fracture barrier zones. The reservoir extends up to several hundred feet in thickness with varying quality and production potential. A careful planning of completion technique and choice of stimulation is important for efficient fracture coverage and improved hydrocarbon recovery. This paper addresses the general methodology of selecting perforation intervals and stimulation technique to develop and enhance production in the Khuff carbonate gas reservoir.
Phase Behavior of Highly Waxy Gas Condensate Systems
Authors: Luo Kai , Li Shi , Zheng Xitan , Liu Henian , Zhong Taixian , Zhu Yuxin 
Published: December 2007

AbstractAs still deeper formations are drilled, gas condensates containing high carbon-number hydrocarbons which may precipitate during production and in the reservoir, are encountered. An increasing focus of attention on its phase behavior has been made worldwide in recent years. The main purpose of this paper is to investigate experimentally the characteristics of phase behavior of this new type of gas condensate systems with high wax content. Therefore, a series of experiments are carefully made for different GOR fluids, including constant composition expansions and the determination of wax deposition points. The separator gas and liquid are collected from the same producer and recombined in the laboratory to cover the ranges of GOR encountered in the field.The results show that the quality lines of the highest GOR fluid in two-phase region are parallel to each other and terminated at the appearance of wax deposition. Thus the fluid has no convergence point, or critical point. It is also found that the biphase regions expand with the increase in GOR. In other words, gas injection may highly increases the saturation pressure locus contrary to the usual belief that the two-phase region will become smaller as more gas injected into the reservoir leads to more leanness of the reservoir fluid. Another interesting finding is that the more amounts the heavy hydrocarbons, the lower dew- & bubble- point pressures of the gas condensate systems used in this study. This is also contrary to the previous literature results that increasing amounts of heavy hydrocarbons increase the retrograde dew point pressure. Thus the deduced conclusion28 that a compositional gradient in the segregated fluids results in higher observed dew point pressures at the bottom of the fluid column, may not be made to the highly waxy gas condensate systems used in this study.Additionally we also found the wax deposition temperature increased with decreasing GOR.
The Compositional Characterization of Gas Condensate Fluids - A Review Featuring the Impact of the Analysis Data Quality on the Accuracy of Equation of State Based PVT Predictions
Authors: Broad T. J. , Varotsis N. , Pasadakis N. 
Published: December 2007

Abstract
The compositional analysis of gas condensate reservoir fluids is an integral part of their routine PVT laboratory analysis. Naturally occurring hydrocarbon mixtures contain thousands of components, the presence and concentration of which determine their physical properties and phase behavior during production. Accurate compositional data is the prerequisite for generating reliable Equation-of-State (EoS) based predictions of the PVT and physical properties of the reservoir fluids over a wide range of conditions as well as for quality assurance of the crude.
Unfortunately, no standard methods are available in the petroleum industry for measuring compositions. Different analytical techniques are employed for obtaining the molecular composition of tank oil such as direct injection analysis, simulated distillation by gas chromatography, separation of the sample by fractional distillation, identification of specific compounds by mass spectrometry, component group distributions by High Pressure Liquid Chromatography (HPLC), etc. In addition, several correlations are utilised for defining the physical properties of the single carbon number fractions (SCNF) and of the heavy end fraction. This diversification inevitably leads to differences in the compositions reported by various laboratories which can significantly affect the quality of the predictions provided by the EoS based simulators.
This paper reviews the current analytical techniques and discusses their advantages and disadvantages. The compositional data obtained on gas condensate reservoir fluids by gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and fractional distillation are compared and assessed. The effects that the differences in the derived molecular compositions bear on the EoS based predictions of the physical properties of petroleum fluids are illustrated using test cases studied in the PVT lab. These effects are particularly pronounced for the estimation of the retrograde liquid deposit curve, which constitutes a crucial set of data for efficient reservoir management.
Adjustment of Differential Liberation Data to Separator Conditions
Authors: Al-Marhoun Muhammad A. 
Published: December 2007

Abstract
The actual reservoir process is neither flash nor differential. Thus, regardless of the testing procedure, some adjustment needs to be made to the resultant data to approximate the fluid behavior in the oil production process. The conventional method of adjustment extrapolates to negative values of solution gas-oil ratio and formation volume factor leads to values less than one at low pressure. Both extrapolations do not conform to the physical behavior. This is due to the fact that the conventional approach does not observe that the oil relative density at reservoir conditions is the same regardless of the process.
This paper presents a new approach to the adjustment of differential liberation data to separator conditions. This approach is based on the fact that both flash and differential data should give the same value for the oil relative density at the reservoir conditions. This is achieved by correcting all the properties, i.e. solution gas-oil ratio, formation volume factor, gas relative density and oil relative density. The new method overcomes the disadvantages and limitation of the conventional approach. This method is tested on 400 PVT files from all over the world and the result is consistent with physical behavior. A sample calculation is presented to outline the new method.