bluuebunny/crossref_metadata_2025_split huggingface dataset:
Single Medium Simulation of Reservoirs with Conductive Faults and Fractures
Authors: van Lingen Paul , Sengul Mustafa , Daniel Jean-Marc , Cosentino Luca 
Published: December 2007

Abstract
This paper describes a technique to incorporate conductive faults and -fractures in a reservoir simulation model. The technique is appropriate for reservoirs with significant primary matrix productivity, and a large spacing between fractures (in the order of tens of meters). The single porosity (one grid) formulation is applied. Any fracture geometry can be represented accurately without grid modifications. The key elements of the approach are pseudo relative permeability curves for grid bocks containing fractures. These curves are determined through an analytical procedure, based on the local fracture and matrix properties. The method is applied successfully to a Middle East carbonate reservoir.
Investigation of H2S Migration In Marjan Complex
Authors: Al-Eid Mohammad I. , Kokal Sunil L. , Carrigan William J. , Al-Dubaisi Jaffar M. , Halpern Henry I. , Al-Juraid Jamal I. 
Published: December 2007

Abstract
Marjan complex is a large offshore oil field located in the Arabian Gulf and is composed of four fields: Marjan 1, Marjan 2, Marjan 3 and Marjan 4. Currently production in the complex is limited to the Khafji reservoir. For several years, it was known that the H2S concentration in the Khafji reservoir varied across the complex. A comprehensive study was initiated to map the concentration profile of H2S across the complex and to address the migration of H2S within it. This included area-wide well-stream H2S measurement and geochemical fingerprinting of Marjan oils. For the first time, the concentrations of H2S were mapped across the complex. The southern and southwestern wells show relatively high concentrations of H2S, and the northern wells show no, or negligible amounts of H2S (less than 10 ppm). The migration of H2S into the northern part of the field has serious implications because the crude handling facilities, or the gas-oil separation plant (GOSP), were designed for sweet crude processing. If migration is proven, the facilities in the northern part of the field need to be upgraded to handle sour crude.
The results of this study indicate that there is a ‘hot’ spot of high H2S located in the southwestern part of the complex. There is a significant H2S gradient across the Marjan complex with H2S decreasing from the southwest to the northeast. H2S concentration profiles with time also indicate that there is an increase in H2S concentration with time in the hot spot. The data negate the possibility of H2S generation in the Khafji reservoir from either sulfate reducing bacteria (SRB) or thermochemical sulfate reduction (TSR). Therefore, it is suggested that the H2S is migrating into the Khafji reservoir from somewhere else, probably from the Ratawi or other, deeper reservoirs.
The geochemical analyses show that the hydrocarbon composition is very uniform across the complex, and there is no evidence for barriers to fluid flow within the Khafji reservoir. It is proposed that the lateral migration of H2S within the reservoir is arrested due to the presence of H2S-scavenging iron minerals. Two hypotheses are proposed for the migration of H2S into the Khafji reservoir from the Ratawi reservoir: (a) through inter-reservoir faults, or (b) through channeling leaks behind well casings. These two hypotheses are discussed in the paper.
Optimization of Gas Condensate Reservoir Development by Coupling Reservoir Modeling and Hydraulic Fracturing Design
Authors: Aly A. M. , El-Banbi A. H. , Holditch S. A. , Wahdan M. , Salah N. , Aly N. M. , Boerrigter P. 
Published: December 2007

Abstract
This paper presents the results of a study that included both compositional reservoir simulation and hydraulic fracture modeling. These models were used to optimize the production and recovery from a rich gas condensate reservoir.
The study illustrates the upside potential of creating propped hydraulic fractures in a gas condensate reservoir. The reservoir is a multi-layered, low permeability, rich gas condensate formation. We performed this study to investigate the possibility of enhancing productivity from the reservoir and to increase gas recovery.
Several wells existed in the field before the fracture treatment campaign was initiated. In this paper, we highlight modeling of three types of wells: vertical wells, vertical wells with multiple fractures, and horizontal wells. In all cases, the effect of condensate dropout around the well and/or the fracture is investigated. The effect of improving the relative permeability due to high velocity around wells is also discussed.
The successful integration of reservoir and fracture modeling resulted in 40% cost savings when compared to the original development plan.
The Obaiyed Gas Recovery Project - A Fully Integrated Study
Authors: Bouman M. , Koopman A. , Ibrahim N. S. 
Published: December 2007

Abstract
A fully integrated study was required to solve the puzzle of the rapidly declining reservoir pressures in the Obaiyed Field. A more regional sedimentological and structural approach formed the basis for a new reservoir model. Consequently the field is now subdivided in a number of discrete blocks, each with its own static and dynamic parameters to predict reservoir properties.
Maximising Value from a Complex Fluvial Reservoir in South Oman: Results from an Integrated PE Study of the Zauliyah Field
Authors: Otiocha James O. , Al-Bulushi Abdulwahab , Al-Harthy Khalfan S. 
Published: December 2007

Abstract
An integrated PE review of Zauliyah field was necessitated by the poor field performance under depletion drive. The review resulted in a new reservoir model conducive to a water injection scheme. Consequently, the field is currently being re-developed by waterflooding. This project phase is accelerated, and will develop 4.0 million m3 of reserves at an average unit technical cost of less than $2/bbl.

General
The Zauliyah field is a NW-SE trending anticlinal structure (Figure 1) that contains light oil (44 API) in five stacked reservoir units of the Permian Upper and Middle Gharif fluvial sandstones. A 25-meter thick shale layer separates the Upper Gharif [UG] reservoirs (20-23% porosity, 8-20% net/gross) from the Middle Gharif [MG] reservoirs (19-23% porosity, 25-51% net/gross).
Discovered in 1981 and with a booked STOIIP of 56 mln m3, the field came on stream in 1984. 14 vertical wells have been drilled (ZL-11 was cored, while ZL-12 has FMI data). The initial development by depletion drive recovered only 6% of the STOIIP before reservoir pressure in most parts of the reservoir units declined to below bubble point. A waterflood programme was considered but could not be embarked upon for risk that the reservoirs were isolated and highly compartmentalised (Figure 2). Therefore, the field continued to produce by depletion drive, but most wells had to be closed-in intermittently due to excessive gas production and flaring. Under these circumstances, the development of booked reserves was not economically attractive, making reserves de-booking imminent at the time. However, this view changed following a multi-disciplinary PE study and water injection pilot schemes. It is now planned to book additional reserves in 2001, and the re-development of the Zauliyah field by water injection has been put on fast track.
The e-Field -- (The Electric Oilfield)
Authors: Jack Ian 
Published: December 2007

Abstract
Time lapse seismic ("4D") shows an impressive growth curve. Recent work on multi-component data ("4C") also shows good potential for the future. These technologies offer ways in which we could improve our reservoir management. For time lapse work, new techniques should allow us to improve the threshold for detection of the seismic effects of pressure and fluid changes. Furthermore, these techniques will allow re-shoots at minimal cost, on a schedule driven by the needs of the reservoir engineers. For multi-component technology, the benefits of imaging with shear waves through gas-filled sediments are already well demonstrated. However, gas clouds are only one of several problems which can be impacted -- there are many potential benefits to be had from this technology, especially in the marine environment.
It seems very likely that these two major new technologies will merge. A strong enabler would be the availability of affordable emplaceable seismic detector systems. For example, if a system could be installed for not much more than a conventional towed-cable seismic survey, it would be irresistible and would open up an entirely new market. We will then have the beginnings of what we might call an "electric oilfield" or "e-field". Our vision is that by combining the imaging techniques above with continuously available engineering data such as pressure, temperature, and saturation coming from emplaced downhole instrumentation, we will achieve a step improvement in reservoir surveillance and thus allow our engineers to improve the management of their reservoirs. The challenges will be to speed the implementation of these systems and to integrate the data successfully, because historically new technologies take years to achieve acceptance. "Cost" and "value" have to be understood and reconciled, and this takes time.
Integrated Development and Early Production Scheme for the Burgan Reservoir in the Soroosh and Nowrooz Fields Offshore Iran
Authors: Denby P. , de Groot H. I. , Guit F. , Willet A. 
Published: December 2007

Abstract
The Soroosh and Nowrooz fields were offered to the industry by NIOC, under the ‘buy-back’ arrangement, in July 1998. In November 1999 a service contract for an integrated development of both fields was signed between NIOC and Shell. The service contract calls for an early oil production system on Soroosh, producing 60,000 bopd of oil within 24 months and 190,000 bopd oil production (100,000 bopd from Soroosh and 90,000 bopd from Nowrooz) from permanent production facilities within 45 months of the signing date.
The Soroosh Field is located some 80 km WSW of Kharg Island (figure 1). The field was discovered in 1962 by IPAC, the former operator and to date fourteen wells have been drilled. Cumulative production in 1979, when the field was shut-in, totaled just over 86 million bbl from the Burgan B mainly from the crest with two wells showing signs of water breakthrough. Crude analyses suggest the presence of a density gradient over the oil column in the main Burgan B reservoir at depths of 2,131 mss down to an oil-water-contact at 2,272 mss. High viscosities over the base of the oil column possibly reduce aquifer support. Definition of fluid property distribution and prediction of the oil-water displacement process present the main challenges.
The Nowrooz Field is located some 80 km WNW of Kharg Island. Agip, the former operator, discovered the field in 1966 and to date fifteen wells have been drilled. Historic production, also from the Burgan B (or Nahr Umr Sand as it was previously referred to), totals around 100 million bbl, with one wet producer. The crest of the structure is at 2,230 mss with an OWC at around 2,337 mss. The structure is heavily faulted along the crest, however, pressure support has not been an issue and a volumetrically large flank aquifer is expected to provide sufficient reservoir drive. Prediction of fault patterns and reservoir development presents the main challenge to the subsurface development.
In the project to date, 3D seismic data acquisition, geophysical and geotechnical surveys have been carried out. Seismic processing and interpretation was ongoing at the time of writing this paper.
This paper describes remaining development uncertainties, and how these will be addressed during the forthcoming production drilling and early production phase.
The Challenges and Way Forward of Horizontal Dual Lateral Wells in Fahud Matrix Reservoir
Authors: Al-Khodhori Shaikhan 
Published: December 2007

Abstract
The Fahud field, on stream since 1967, is being the largest field in Oman in term of STOIIP 1×10(9) m3. This great carbonate field, initially produced by natural depletion, followed by gas injection in 1968, water flooding drive in 1972 and is now being produced by gas-oil gravity drainage process (GOGD) since 1984. The field once thought to be completely covered with fractured reservoir, hence only GOGD development with crestal gas injection for voidage replacement has recently being also developed by water flooding in Shuiaba and Natih matrix reservoir.
The dual lateral completion aims to maximize the productivity from relatively low permeability matrix units. The two laterals are normally completed barefoot (Level 2 multilateral) with a single selective 3 ½" gas lift completion. As completion stays simple and cost effective, lateral re-entry remains one of the main challenge. Different technologies have been applied to address various completion challenges in these dual laterals, with various degrees of success. For instance a pre-milled secure window at the junction to allow upper lateral re-entry has been applied with technical success but hindered 7" liner cementation. Other areas that have been atried in dual laterals are improving acid stimulation techniques, lifting optimization, improving well design to overcome hole problem, improve liner cementation, producing and monitoring each lateral, etc. at different degrees of success.
This paper is intended to cover all these major challenges facing Fahud horizontal dual lateral wells matrix reservoirs, technologies applied and their outcomes (success and failures), and foreseen future completion issues in term of subsurface characteristics uncertainties and way forward. Given such a large STOOIP, and the fact that GOGD process has slow and low recovery factor, maximizing these low permeability matrix units is essential for the field production.
Field Pilot Test of Thermal Stimulation of Rubble Reservoir Using Down Hole Induction Heaters
Authors: Sivakumar V. C. Babu 
Published: December 2007

Abstract
Production of the viscous heavy oil from the shallow Rubble reservoir (about 1500-1600’) in the Bahrain field has been a challenge given its low gravity (12-18° API) and high viscosity (350 cps at 40° C). It was planned to carry out a trial test of thermally stimulating the formation to improve the production rates from this reservoir using a downhole heater. Since the greatest pressure drop in a producing well is always near the well bore application of heat at the well bore to reduce the oil viscosity can result in dramatic increases in oil production. The trial test showed an increase in oil production from &lt; 10 bopd to about 70 bopd initially and later stabilized at about 40 bopd. Even a modest increase in downhole temperature was seen to have a significant effect on both the water cuts and production rates.
Of the various types of downhole heaters available it was chosen to install an induction type of heater in view of the various inherent advantages. Primarily, these heaters could be installed in wells with no special completion requirements. The Inductor tool assembly utilizes the electrical energy to inductively heat the reservoir through the Ferro-magnetic casing. Efficient three-phase power delivery through an ESP cable using high voltage and low current minimizes resistive power losses and as much as 80-85% of the delivered power can be converted into heat.
The paper deals with the trial installation, operation problems encountered and the production performance of the well on trial. Based on the success of the pilot additional installations are being planned for trials in two more wells with heavier and more viscous oil quality.
Producing the Ultimate from the Saih Rawl Shuaiba Reservoir
Authors: Senger Jens-Christian , Al-Harthi Nasser R. , Avest Dick ter , al-Bahry Alia , Bigno Yann 
Published: December 2007

Abstract
Horizontal drilling of multilateral wells within the last five years has rapidly developed the Saih Rawl Shuaiba reservoir. These wells consist of up to 7 branches, and expose more than 10 km openhole of reservoir per well. Current production of the reservoir is around 8,000 m3/d of oil with an average watercut of 75%. A "produce-the-ultimate"-initiative was followed to systematically analyze, debottleneck and optimize every detail of the production chain: from water injection manifold, water injectors, to oil producers with ESP, including the waterflood efficiency. This has resulted in a range of optimization activities such as ESP changeout, flowline looping, water injector tubing resizing, automation of chokes and an improved water injection distribution system. Initial gains from part of these activities amount to more than 1,000 m3 of oil per day within the first six months.
Influences of Asphaltene Deposition on Rock/Fluid Properties of Low Permeability Carbonate Reservoirs
Authors: Shedid Shedid A. 
Published: December 2007

Abstract
Asphaltene deposition has profound effects on oil flow through porous medium. The investigation of the influences of asphaltene precipitation on carbonate reservoir rocks has minor interests in comparison to studies investigated sandstones ones. Therefore, this study is undertaken to provide accurate insights, especially for carbonate reservoirs of low permeability.
In this study, two groups of experiments are undertaken. The first experimental group investigates effects of asphaltene precipitation on (a) petrophysical properties of carbonate rocks, including absolute permeability, effective porosity, and hydraulic radius, and (b) on oil-water relative permeability and water flooding performance. The second group searches for the effects of asphaltene precipitation on capillary pressure and pore size distribution of low permeability carbonate reservoirs. Conducted experiments are achieved using actual reservoir liquids of crude oil and brine, flowing through actual carbonate cores under similar reservoir conditions of temperature and pressure.
The results indicated that asphaltene precipitation damages absolute permeability and hydraulic radius drastically, reduces effective porosity, and improves relative permeability of water for different asphaltene contents of crude oil flowing through carbonate reservoirs. In addition, oil reservoirs of high asphaltene content have shown higher values of irreducible water saturation than that ones of low asphaltene content in their crude oils. Precipitation of asphaltene in carbonate rock causes changes in the position of capillary pressure at high mobile oil saturation and reduces values resulted for pore size distribution curves, especially for small pore radii carrying crude’s of high asphaltene content.
Neglecting the proven influences of asphaltene precipitation may lead to erroneous description of carbonate reservoirs. Therefore, analysis of petrophysical properties and pore size distribution of carbonate reservoirs has to be updated during the extended life of oil reservoir and based upon accurate values of asphaltene content of the flowing crude oils.
Applications of the attained results of this study are expected to provide real improvement in reservoir description, more reliable estimation of oil reserves, accurate predicted values of reservoir rock damage, and also better descriptive functions for future reservoir simulation studies.
Prediction of Oil PVT Properties Using Neural Networks
Authors: Osman E. A. , Abdel-Wahhab O. A. , Al-Marhoun M. A. 
Published: December 2007

Abstract
Reservoir fluid properties are very important in reservoir engineering computations such as material balance calculations, well test analysis, reserve estimates, and numerical reservoir simulations. Ideally, these properties should be obtained from actual measurements. Quite often, however, these measurements are either not available, or very costly to obtain. In such cases, empirically derived correlations are used to predict the needed properties. All computations, therefore, will depend on the accuracy of the correlations used for predicting the fluid properties.
This study presents Artificial Neural Networks (ANN) model for predicting the formation volume factor at the bubble point pressure. The model is developed using 803 published data from the Middle East, Malaysia, Colombia, and Gulf of Mexico fields. One-half of the data was used to train the ANN models, one quarter to cross-validate the relationships established during the training process and the remaining one quarter to test the models to evaluate their accuracy and trend stability. The results show that the developed model provides better predictions and higher accuracy than the published empirical correlations. The present model provides predictions of the formation volume factor at the bubble point pressure with an absolute average percent error of 1.789%, a standard deviation of 2.2053% and correlation coefficient of 0.988. Trend tests were performed to check the behavior of the predicted values of Bob for any change in reservoir temperature, Gas Oil Ratio (GOR), gas gravity and oil gravity. The trends were found to obey the physical laws.
Scale Inhibitor Injection Via the Gas Lift System in High Temperature Block 3 Fields in Angola
Authors: Poggesi Guido , Hurtevent Christian , Brazy Jean Louis 
Published: December 2007

Abstract
When scale problems occur into the tubings, without hardly affecting the well productivity, it can be interesting to find new downhole injection means, representing an alternative to classical squeezes.
On some wells of block 3 in Angola, the squeezes turned out difficult because of the reservoir heterogeneity and temperature (164°C). The reservoir being dolomitic most of the inhibitors show a strong incompatibility and precipitate when injected. The operator of these fields preferred to turn to an inhibitor injection via the gas lift system.
This injection is made possible, because scales, made by calcium carbonate and barium sulphate, do not affect the well bottom but only the tubing. The gas lift valves are located under the area where scale begins to form and the inhibitor injection through the gas lift system permits the prevention of scale precipitation into the wells without having to perform squeeze treatments.
Injection via the gas lift began with standard inhibitors dissolved in water to which VPD (vapor pressure depressants) were added.
In spite of the presence of VPD, water evaporation caused the formation of gums and a rapid clogging of the gas-lift valves. Therefore a solid scale inhibitor was used and diluted in solvents with a very high boiling point, so that it would not evaporate at well temperature, i.e. 164 °C.
The case history we are presenting, describes the design of the scale inhibitor, the injection and the follow-up which have been carried out in Angola on 11 wells in Block 3 fields.