bluuebunny/crossref_metadata_2025_split huggingface dataset:
Upscaling and Discretization Errors in Reservoir Simulation
Authors: Sablok R. , Aziz K. 
Published: December 2007

Abstract
Reservoir simulation models are used as an everyday tool for reservoir management. The number of grid blocks in a simulation model is generally much smaller than the number of the grid blocks in the geological model. The geological model is therefore regularly upscaled for building reasonably sized simulation models. Any upscaling causes a loss in detail and introduces errors. Understanding the nature of the errors that occur due to the upscaling step is important because it can provide a handle on the kind of upscaling to be performed and the optimum level of upscaling. Furthermore, understanding interaction of gridding and upscaling errors is essential for building reliable simulation models. In this paper we analyze errors introduced due to the upscaling step.
Firstly, the generality of the purely local single phase upscaling is considered and the errors introduced due to its use in complex multiphase flows are investigated. Three kinds of errors, namely total upscaling errors, discretization errors, and errors due to the loss of heterogeneity are defined and their behavior as a function of the level of upscaling is studied for different types of permeability distributions. The reasons for apparently low total upscaling errors at high levels of upscaling are investigated. The efficacy of the geostatistical tools (variograms, QQ plots) for understanding the geological structure of the upscaled models as compared to the reference model is tested for different cases.
Secondly, the uncertainty introduced in the flow results due to the upscaling errors is studied in conjunction with the uncertainty incorporated through the introduction of geological variability in the ensemble of geological models. The behavior of upscaling errors and geological variability as a function of level of upscaling is studied, and its possible impact on important reservoir management decisions, is analyzed. It is shown that the uncertainty models of cumulative oil profiles, obtained from flow results of highly upscaled models can contain significant uncertainties. These uncertainties are a result of upscaling errors and therefore cannot be considered to represent only geological uncertainty, which is captured by the introduction of geological variability in the ensemble of the geological models.
Evaluation of Residual Oil Saturation and Recovery Efficiency of Two Distinct Arabian Carbonate Reservoirs
Authors: Okasha T. M. , Funk J. J. , Al-Shiwaish A. A. 
Published: December 2007

Abstract
Saudi Arabia has a variety of carbonate reservoirs of different geologic ages. Such reservoirs are characterized by heterogeneous rock properties. These heterogeneities are caused by wide spectrum of environments in which carbonates are deposited and subsequent alteration of original rock fabric.
Extensive SCAL work was carried out on preserved core plugs recovered from two distinct carbonate reservoirs. The first reservoir is a Late Jurassic Arab-D offshore carbonate reservoir (Abu Safah field). The second one is Shu'aiba reservoir (Lower Cretaceous) located in Rub’ Al-Khali in southeastern Saudi Arabia. The purpose of this study is to provide and evaluate waterflood recovery efficiency and residual oil saturations of the two distinct Arabian reservoirs.
Variation of oil recovery and residual oil saturation between the two distinct reservoirs is due to variations of rock characteristics especially the relationship of textural and diagenetic features which affect the size and distribution of pore throats. Shu'aiba reservoir rock could be classified as wackstone which demonstrates a higher ratio of lime mud to detrital grains (pore sizes ~ 0.27 to 1.5 microns). On the other hand, Arab-D reservoir is classified as grainstone and consists of oolitic limestone and dolomitic limestone with larger pore sizes (0.5 to 5.5 microns).
The results indicated that pore structure, pore size distribution, rock fabric, and environment of deposition are important factors that affect microscopic oil and water flow in porous media and the development efficiency of an oil field developed by water injection. Oil recovery from Arab-D reservoir is slightly higher than that of Shu'aiba reservoir. The residual oil saturations values for Arab-D reservoir were also found to be slightly higher than those of Shu'aiba reservoir. Arab-D reservoir showed less permeability dependence for both (Swir and Sor) end point saturations.
Successful Use of Horizontal Well Technology in Mitigating Water Production and Increasing Oil Recovery in the South Umm Gudair Field, PNZ, Kuwait
Authors: Barge D. , Tran T. , Al-Shaarawy O. , Jha M. , Hagtvedt B. , Al-Haimer M. , Al-Harbi M. 
Published: December 2007

Abstract
The producing history of the South Umm Gudair Field (SUG) is characterized by increasing water cuts and increasing decline rates. Several different conventional techniques were applied to mitigate the effects of water encroachment. Results from applying these techniques were mixed. While some earlier applications looked promising, later applications were often marginal. As a result, horizontal sidetracking was introduced in the SUG field. A total of 15 horizontal sidetracks were performed from 1999 to 2004, resulting in both increases in oil production and reduction in water cut. This paper presents the results of sidetracking 15 wells in the SUG field to mitigate water encroachment and increase oil recovery.
Oil-Water Separation Experience from a Large Oil Field
Authors: Kokal S. , Al-Ghamdi A. 
Published: December 2007

Abstract
This paper discusses challenges related to emulsions that have been encountered in a large Saudi Arabian field. The field produces from several different reservoirs with a range of fluid properties. These properties provide an interesting case of operational challenges in oil-water separation including increased incidents of shorting in the separator, tripping of equipment and increased demulsifier consumption.
This paper presents the results of a comprehensive study that was initiated to understand the main causes of emulsion formation in the field and ways to optimize oil-water separation. The effect of several recommendations that were implemented by operations engineering in the field were evaluated. These include the conversion of a two-phase separator into a three-phase separator, splitting of the demulsifier injection between offshore producing platforms and onshore wet crude handling facilities, and field trials with promising chemicals. The demulsifier costs have been reduced by over 50% by the implementation of retrofitting and proper demulsifier injection strategies. The results presented in the paper provide invaluable operational experience and many lessons learned are applicable to any crude-oil treating facilities.
Sulfur Disposal by Acid Gas Injection: A Road Map and a Feasibility Study
Authors: Kokal S. , Al-Utaibi A. 
Published: December 2007

Abstract
Sour natural gas contains H2S and CO2, which have to be removed to meet specifications for sales gas. The removal process is done at the gas plants. The resulting acid gas streams (primarily H2S and CO2) are processed in sulfur recovery units or sulfur plants, which convert the H2S to elemental sulfur instead of burning it and flaring the produced SO2. The sulfur recovery units (SRU) are not a major revenue generator (due to the low sulfur price) and are primarily installed for environmental reasons.
The total world sulfur production is anticipated to increase in the future, causing a downward pressure on sulfur prices. With low sulfur prices and large stockpiles of sulfur, it is worthwhile to consider alternate processes for handling sulfur. One such alternate is the injection of acid gas into a subsurface reservoir, much like injecting the produced water during crude oil production.
Acid gas injection has several advantages and disadvantages. Advantages include low operating expenses, reduced sulfur emissions into the atmosphere, CO2 sequestration and the ability to handle wide range of acid gas compositions. Disadvantages include finding a geologically isolated disposal or storage reservoir, increased safety risks, subsurface migration and lost revenues from sulfur. Any one of these could be the controlling factor, and a detailed economic and environmental analysis is needed to decide whether an acid gas injection (AGI) scheme should be installed in lieu of sulfur recovery plant. The existing AGI schemes are primarily installed in Canada (a few in the USA) due to low sulfur prices, increased environmental regulations making it mandatory for operators to control sulfur emissions into the atmosphere, and availability of suitable depleted oil and gas reservoirs.
This paper presents a roadmap for acid gas injection schemes including the technical and economic factors that need to be addressed in deciding whether AGI is feasible. An example feasibility study for a Saudi Arabian field is included as a case study.
Measurement and Simulation of Low Vapor Pressure Blends of NGL and Stabilized Crude
Authors: Kokal S. , Meeranpillai N. S. , Al-Otaibi F. M. , Al-Madani E. 
Published: December 2007

Abstract
Due to operational constraints natural gas liquids (NGL) are sometimes blended with stabilized crude. This option is considered when there is a temporary surplus of NGL and for better NGL management. The NGL blend ratios are generally very small and conservative and are not meant to impact the crude quality. The blends have to meet rigorous vapor pressure specifications.
A systematic study was conducted to determine the vapor pressures of different NGL/crude oil blends. The evaluation considered various factors that impact the vapor pressure of the blends, including the NGL/crude oil ratios, degree of crude stabilization, temperature, and the retention time in the pipeline and/or in the crude tanks. An important aspect of the study was to determine the "foaming tendency" and volume changes during blending. Vapor pressure curves were determined for different blends of stabilized crude with NGL as a function of temperature. The data included both the true vapor pressure and Reid vapor pressure of the blends. The experimental data were supplemented with equation of state simulations. Low vapor pressure data of blends are scarce, and the paper discusses the physical properties of NGL/crude oil blends.
Application of Formation Testing While Drilling in the Middle East
Authors: Seifert D. J. , Al-Dossari S. , Burinda B. J. , Kellet S. 
Published: December 2007

Abstract
In recent years, Measurement While Drilling / Logging While Drilling, MWD/LWD, formation evaluation applications have evolved to a point where many applications usually reserved for wireline logging can now be utilized using LWD technology. The latest of such applications come from formation testing while drilling tools which offer an alternative to wireline-based formation testing. Formation pressure data obtained while drilling is useful for traditional applications such as fluid typing, fluid contacts, and reservoir connectivity/isolation determination as well as for improved well control with real-time measurement of pore pressures.
This paper presents a case history from the Middle East where a new Formation Tester While Drilling (FTWD) tool has recently been run. The tool utilizes a probe and packer concept similar to conventional wireline formation testers. A packer and probe are extended to the formation, and a small sample chamber is used to pressure test the formation. To obtain a formation pressure, it is required to stop drilling for a minimal period. Experience has shown this time period to be typically less than the time required to make a connection.
Field data from Saudi Arabia will be presented, where the Formation Tester While Drilling (FTWD) tool was recently run. The tool's operation, response, and applications of the data obtained are discussed.
Immiscible Displacement of Non-Newtonian Fluids in Communicating Stratified Reservoirs
Authors: El-Khatib N. 
Published: December 2007

Abstract
The displacement of non-Newtonian power-law fluids in communicating stratified reservoirs with a log normal permeability distribution is studied. Equations are derived for the fractional oil recovery, water cut, and injectivity ratio at times of breakthrough in the successive layers of the reservoir. Many of the resulting equations are implicit in nature and an iterative solution procedure is used. Expressions are also derived for the pseudo relative permeabilities as function of the average saturation.The performance is compared with that for the Newtonian fluids. The effect of the different parameters on the performance is investigated. These parameters included the apparent mobilityity ratio, the power-law flow behavior indexes, the Dykstra-Parsons variation coefficient, and the flow rate. Constant injection rate and constant total pressure drop cases are studied.
Design and Application of a Novel HT/HP "Stirred Reactor" Test Rig To Study Scale Formation and Control
Authors: Graham G. M. , Williams H. L , Wat R. , Tau L. A. , Wennberg K. E. 
Published: December 2007

Abstract
In several HT/HP production environments severe downhole carbonate scale is often anticipated. Moreover, the high temperature means that reaction kinetics are very rapid and therefore the propensity for scale formation remains high even at moderate levels of oversaturation. However, a number of limitations are recognised when assessing the scale risks associated with such production conditions. This includes; uncertainties regarding the initial FW composition, accuracy of scale prediction tools and the application of conventional laboratory test procedures under these conditions. This paper describes the use of a novel HT/HP stirred reactor test rig (400F & 5,000 psi) designed to conduct in situ scaling experiments and allow equilibrium conditions to be established. The equipment is specially designed for the extraction and stabilisation of samples at or near tested conditions allowing the equilibrium brine composition to be determined under more representative HT/HP conditions. Initial results presented in this paper describe the commissioning and validation of the experimental design including the use of tracers to ensure effective transfer and collection of fluids from the reaction vessel. Results are then presented to determine the equilibrium saturation state of a particular field brine starting from the supplied water composition. In summary equilibrium saturation tests conducted at 340F and pressures between 200 psi and 5,000 psi showed significant quantities of carbonate scale (both barium and calcium carbonate) precipitating from solution, indicating a potential uncertainty in the original brine composition.
In summary, the data generated allows equilibrium saturation levels to be determined under HT/HP conditions allowing uncertainties in the water composition to be assessed. The determined saturation levels are also directly correlated with dynamic tube blocking tests and scale prediction tools. The data can therefore be used to further tune predictive modelling capabilities under these more extreme (HT/HP and high salinity) conditions.
Minimum Platform Designs - Cook Inlet, Alaska
Authors: Visser R. C. 
Published: December 2007

Abstract
The paper describes two minimum-cost, self-erecting, platform designs and one caisson structure design that can be installed in Cook Inlet, Alaska without the need for heavy lifting equipment. The Cook Inlet environment is characterized by thirty-foot tides and during the winter months by fast moving ice floes. The area is remote from other offshore operating areas and there is no heavy lifting equipment. One of the designs has been built and platform Osprey was installed in Cook Inlet in 2000. The paper will describe how it was designed, constructed and installed. A, second, different design concept allows platform installation in deeper water, again without the need for heavy lifting equipment. The third design concept is an outrigger caisson design that can be installed with a jack-up drilling unit. It would have application as a satellite platform structure.
Use of these minimum-cost platform and caisson designs would enable development of marginal fields in Cook Inlet that heretofore could not be developed because the high cost of mobilizing and demobilizing heavy lifting equipment to and from Cook Inlet would make development uneconomic.
Using Real-Time Pressure Data for Well Placement Planning
Authors: Parker M. , Bradford R. N. , Corbett C. , Heim R. N. , Isakson C. L. , Broome S. S. , Proano E. 
Published: December 2007

Abstract
Well placement decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed reservoir parameters, especially the presence of a connected aquifer and its size, with a set of simulation models to assist with well placement decisions.
In the South Timbalier 316 block, a delineation well penetrated the steeply dipping B4 reservoir near the oil/water contact. Based on a comparison of downhole pressure data, with data from simulation models, the operator concluded that a connected aquifer was present and estimated its size. This information was sufficient for the operator to know that the well would not be needed as a water injector and to justify a sidetrack from the downdip location to an updip location.
When the updip sidetrack well was drilled, reservoir rock quality was below the minimum for a commercial completion. This brought into question the viability of any hydrocarbon storage capacity in the northern portion of the field. As soon as the updip sidetrack well was logged, a "what-if" reservoir model was run to simulate a no-hydrocarbon-reservoir scenario in the northern portion of the field. This reduction represented approximately 25% of the reservoir hydrocarbon pore volume. The model results clearly indicated that this was not a reasonable model and gave the operator confidence to sidetrack the well directly to the west, to a slightly downstructure position, whereby a successful completion was made. Without this "quick-response reservoir model" the well may have been sidetracked to the south, resulting in a less-than-optimal well location.
Reservoir Characterization and Simulations Studies in a Heterogeneous Pinnacle Reef for CO2 Flooding Purposes: A Case Study
Authors: Al-Dliwe A. , Asghari K. 
Published: December 2007

Abstract
Carbon dioxide injection is an effective method for enhanced oil recovery. In this process, CO2 develops miscibility with the oil under reservoir conditions, and leads to additional oil recovery. Proper reservoir characterization has a significant influence on designing and implementing a successful CO2 flood in a reservoir.
This paper presents the results of a reservoir characterization analysis and simulation in a relatively small reef located in Northern Alberta, Canada, which was selected as a candidate for a CO2 injection project. This reef has a thick oil column spanning a small area with steeply sloping sides, and two wells drilled on the same side of the reef. Open-hole logs and production history data were available for only one of the two wells. Data analyses disclosed a number of challenges that could affect the results of any simulation for predicting the performance of CO2 displacement in this field. These challenges included, but were not limited to, the existence of two no-flow barriers with unknown extensions, lack of other data such as relative permeability, and lack of information on lateral distribution of the reservoir properties. Material balance analysis indicated the maximum oil in place was 4.7 MMSTB with a weak water support.
A fully compositional reservoir simulator (CMG-GEM™) was used with the aim of improving the understanding of the reservoir characteristics, and investigating the suitability of CO2 injection. An 8-component Peng-Robinson EOS was utilized to describe the phase behaviour of the reservoir fluids and injected CO2. History matching was done and the current reservoir pressure was found to be about 1000 psi below the minimum miscibility pressure. A simulation study was conducted and the model predicted an incremental oil recovery of around 1.04 MMSTB and about 0.424 Mt of injected gas stored in the reservoir.
Integration of Advanced Production and Image Logging in a High Gor Horizontal Well with Assessment of Remedial Actions
Authors: Al-Fawwaz A. A. , Mubarak H. K. , Zeybek M. 
Published: December 2007

Abstract
Production logging in high GOR horizontal wells still exhibits difficulties due to multi-phase, complicated flow regimes in undulating long well bores. Accurate diagnosis of gas entries is important for the understanding of the well performance, reservoir dynamics, characterization and if possible, for shut-off remedial action.
In this paper, a case study is presented in a horizontal well with high GOR where oil production decreased significantly due to gas entries. The example horizontal well is located in Saudi Arabian Lower Cretaceous carbonate reservoir that has gas cap and relatively weak aquifer. Although the horizontal well is placed away from the gas cap, increase in GOR was observed after two years of production time. Since GOR increased to over 5000 SCF/STB by then, an integrated production logging tool was utilized to detect gas entries and determine flow profile.
Results showed that the gas entries were detected from the high sides of the well and the majority of the gas was entering from the heel section over 500 ft of interval. Gas hold up in the well bore was determined from gas sensor tool in real time and pulsed neutron tool, providing high confidence. All the sensors exhibited coherent measurements, yielding confident and conclusive results for the gas entries. Image logs and permeability determinations identified the presence of different facies with high permeability over the interrelated entry intervals, supporting the calculated flow profile. The results, observed difficulties and recommendations are discussed for improvements. A single well fine grid numerical reservoir simulation model was also developed to assess impact of remedial action plans.