bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflooding of A Heavy Oil Marginal Reservoir
Authors: Hanafy H. H. , Mansy A. M. 
Published: December 2007

Abstract
This paper shows how Gupco (Gulf of Suez Petroleum Company) has successfully developed a heavy oil marginal reservoir by using high technologies such as reservoir simulation, 3-D visualization, coiled-tube dual completion, and coiled tube pipeline. The July 53 block was discovered in January 1986 with the drilling of the vertical platform proving well J-53. The well was drilled to test the Lower Rudeis formation in a 90-acre sliver block to the west of the main Lower Rudeis July field. The test indicated a potential of 1350 BOPD with an API gravity of 19 degrees, an oil viscosity of 7 CP, and a gas-oil-ratio of 85 SCF/STB. For this reservoir fluid type, the recovery factor was expected to be less than 5% under primary conditions. Therefore, the development of this fault block was put on hold until further studies could determine the optimum plan of depletion. Starting in 1993, GUPCO began studying small reservoirs such as the J53 block with a PC-based black oil simulator. In the case of J53, the simulator was used to match the short term DST from the discovery well, and then create multiple depletion scenarios. Waterflooding, it was discovered, would provide the best development plan. Use of the simulator provided insight into the recovery process, and reduced the development risk. Under primary recovery, the simulator confirmed a low ultimate recovery of 3% of the OOIP. With the optimal waterflooding plan, however, recovery could be improved to 23% of the OOIP. Considering that normal Lower Rudeis oil recovery approach 54% of the OOIP under waterflooding (in the main field with 32 degree API oil), the simulator provided a much more conservative estimate. The development of this fault block was started in May 1996 by drilling a high angle producer designed to be parallel and close to a major fault to encounter the full Lower Rudeis section. Waterflooding was started in December 1996 by completing an existing Nezzazat producer with a unique coiled-tube dual water injection - oil production completion. A 3 1/2 inch coiled tubing line was laid to provide injection water from a near platform at almost 7000 BWPD. Performance to date indicates a successful waterflood project. The well's production rate has increased from 1300 BOPD, before waterflood start, up to the peak production rate of 4100 BOPD.
Asphaltene Characterization and Mitigation in South Kuwait's Marrat Reservoir
Authors: Kabir C. S. , Jamaluddin A. K. M. 
Published: December 2007

Abstract
This study addresses two aspects for mitigating production problems in south Kuwait's Marrat wells in the Magwa area of the Greater Burgan field: (1) characterizing single-phase oil samples collected from four wells, (2) finding a pragmatic and cost-effective solution to tubular deposition problem. We took two approaches for laboratory investigation. In the first approach, gravimetric technique was used to establish asphaltene onset pressures (pao) at various temperatures, leading to generation of the asphaltene deposition envelope (ADE). The second approach entailed the use of acoustic resonance technique (ART) for rapid determination of both the pao and bubblepoint pressure (pb) in one experimental run, en route to the development of a solvent—deasphalted oil.
Fluid characterization also included thermodynamic modeling. Here, asphaltene is treated as a solid phase in equilibrium with the reservoir fluid, which is modeled by an equation-of-state (EOS) model. We reproduced observed features of various isotherms quite well, lending credence to the modeling approach.
Following fluid characterization, we sought a cost-effective and environment-friendly solvent. Search for a solvent led us to the development of deasphalted oil. We designed and conducted a series of experiments to deasphalt the Marrat oil and examine its potency as a solvent. Results showed that the use of 20% deasphalted oil with 1% dispersant, both by volume, can ensure solubility of asphaltenes in the entire flow string during production. EOS modeling on deasphalted oil was also done for computing onset pressures at various temperatures with good success.
HSE Management as an Approach for Efficient Business Management
Authors: Al-Abdali Fatima Kh. 
Published: December 2007

Abstract
KOC aims to achieve high industry standards in health, safety and environmental standards. KOC's management and technical supports believe that good HSE performance is an integral part of efficient and profitable business management. The company has adopted a very comprehensive policy "HSE Policy", which consider three main principles as pillars for the implementation of the policy. These are: Providing safe & healthy operations; Progressively improving the environmental performance; and respecting the interest of its neighbors and the world community. Such broad goals can't be approached without a full commitment and willingness to comply with the new set of standards and technologies that have been developed for this objective.
This paper will highlight on several vital projects that will ensure the overall progress towards KOC's new vision, which is aspiring a leadership in the petroleum industry in the Arabian Gulf Region. Reducing the risk and/or managing the acceptable risk from any petroleum project is a major action plan towards HSE strategy, that could be ensured via the right Environmental Impact Assessment (EIA) procedures and successful winning auditing. The author will present several effective case studies at KOC to include: improving the efficiency of flaring; adopting the down hole injection of produced effluent water for oil production; enhancing the oil based mud drilling cuttings and crude sludge; emission & waste inventory and management projects.
The paper will conclude with the proposed HSE strategic plan of KOC which is calling for progressive improvement in the environmental performance of its facilities and ensuring the fulfillment of the local, regional and international rules, regulations and standards.
Better Understanding of Reservoir Statistics is the Key for Reliable Monte Carlo Simulation
Authors: Macary Sameh M. , Hassan A. , Ragaee E. 
Published: December 2007

Abstract
Nowadays Monte Carlo simulation is getting more applied in the major investment to better evaluate the appraisal of the projects, among which the economic evaluation of the petroleum industry applications forms the majority. One of the most highly appreciable applications of the risk assessment is the estimation of volumetric reserves of hydrocarbon reservoirs. Monte Carlo technique considers entire ranges of the variables of Original Oil in Place (OOIP) formula rather than deterministic figures. The present work demonstrates how statistical distribution and descriptive statistics of porosity, thickness, area, water saturation, recovery factor, and oil formation volume factor affect the simulated OOIP values. The regulating index through this work is the coefficient of variation. The current work presents the case of Ramadan oil field, operated by the Gulf of Suez Petroleum Company (GUPCO), as it is being well defined and developed reservoir. Several runs have been conducted to detect the effect of the mean value, standard deviation, minimum/maximum, most likely values, and to test the influence of distribution type and the number of trials. The study stated that any reservoir engineer who proceeds with Monte Carlo simulation should be careful while fitting the available data to certain distribution. The effect of data vector homogeneity expressed in terms of coefficient of variation seems to be strong in evaluating OOIP and ultimate reserves. The study uses the probabilistic approach to show the certainty level of recovering the remaining reserves.
Prediction of Scaling for the Seawater Injection System at the Northern Kuwaiti Oil Fields
Authors: Salman M. , Al-Hashem A. , Carew J. 
Published: December 2007

Abstract
A computer scaling study was conducted to predict the possibility of scale formation when seawater is injected into the northern Kuwaiti oilfields for reservoir pressure maintenance. Results indicated that the seawater is likely to be self-scaling with respect to calcium carbonate at reservoir conditions. The maximum amount of calcium carbonate precipitation for two formation waters was about 30 mg/kg at 90% injection water. There is also a slight potential for barium sulphate precipitation rising to maximum value of 2.8 mg/kg (formation water A) and 4.2 mg/kg (Formation water B) at 40% injection water at reservoir conditions. Within the production wells, the type and amount of scale predicted are similar for both formation waters A and B. There is a slight potential for calcium carbonate formation, but only at 60% seaater injection break-through ratios. There is also a small, but potentially significant potential for barium sulphate scale precipitation at these conditions. Results also indicated no significant scaling potential for formation water A and B within the surface handling facilities.
Heavy Oil Production in Venezuela: Historical Recap and Scenarios for Next Century
Authors: Layrisse I 
Published: December 2007

Abstract
Traditionally, Venezuela has been a heavy oil producer since 1914, when the first heavy oil commercial well, Zumaque I, was drilled in the Mene Grande field, which at that time showed a 707 millions barrels recoverable reserves.
This wildcat was soon after followed by the discovery of the Bolivar coastal fields, located along eastern coast of the Maracaibo lake, With a combined STOIP of 35 MMM barrels these giant fields where once considered amongst the largest oil accumulations.
During the 1940's the exploration crews discovery a series of heavy oil fields in the eastern Venezuela basin, this work led to the discovery during the early 50's of the so called Orinoco Belt. A huge Stratigraphic trap which contains half of the world's reserves of heavy and extra heavy crude oil.
Nowadays Venezuela, through its oil company PDVSA, produces close to 1 MMBPD of heavy and extra heavy crudes, while current plans aim to double that figure by the year 2005.
This paper would look through the history of the Venezuelan heavy and extra heavy oil development in the country, and how the post second world war political environment influenced such development. Breakthrough technologies in the areas of Chemistry, drilling, lifting and reservoir description in general, have increased the economic value of these reservoirs, making feasible a profitable operation. A series of viable scenarios leading Venezuela into the next century as the major heavy and extra heavy oils producer are devised.
Should It Be Well Weighing or Well Analysis?
Authors: Chastain Joe 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The purpose of this paper is to alert people of the oil industry that the most people of the oil industry that the most important part of the "oil business" is the oil well. Without the oil well there is no oil business!
The oil wells are the most neglected branch of the industry, basically, because they are away out in the country - operated in most cases by the least educated, least trained and least supervised of the personnel. personnel. It may not be producing all that is possible but who knows the difference? This is possible but who knows the difference? This is the reason we must have Well Analysts instead of guys running Dynamometers and Sonologs and passing the charts on to some one else.
To become efficient we must have a "Well Analysis Department"! That may take a Vice-President of the department to make it work!
SHOULD IT BE WELL WEIGHING OR WELL ANALYSIS?
In the beginning we had an oil well! It was away out in the country where, at that time, there was no paved road - only muddy roads and muddy locations or hot dusty roads and hot dusty locations. To a city dude, either was repulsive.
At that time most thought that after a well was drilled and production hit the tank, that was the important thing and the only thing to do now was to sell the oil. The only trouble was that all wells were not that good and some had to be pumped. Then they found that even though the oil was there in the ground it was difficult to produce enough to pay all the debts.
Therefore, it became necessary to find some way to take a look at the problems. There have always been some technical people around and they were enlisted to try to find out some of the answers. It happened that they called these people Engineers.
Two World Depth Records - How to Do It
Authors: Winchell D.H. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Through the use of the most up-to-date drilling technology, Lone Star Producing Company set two drilling depth records below 30,000 feet back-to-back. The two wells, the Baden Unit No. 1, southeast of Elk City, Oklahoma and the Bertha Rogers No. 1, south of Burns Flat, Oklahoma reached depths of 30,050 and 31,441 feet, respectively. Preplanning by Lone Star and the application of the technology compiled by the industry made possible the penetration of the deep Cambrian and pre-Cambrian sedimentary beds in the Anadarko Basin. These drilling efforts proved that equipment and techniques are available to drill below 30,000 feet, and penetration of porous beds below 31,000 feet confirm that reservoir rock to store and produce hydrocarbons can be expected below those depths commonly drilled to date. Various phases of the drilling operations are discussed in detail.

Introduction
The Anadarko Basin in Western Oklahoma and the Oklahoma and Texas Panhandles has long been a challenge to the Panhandles has long been a challenge to the searcher for oil and gas. Sedimentary beds overlie basement rocks from a depth of 40,000 feet along the axis of the basin syncline to a depth of less than 4,000 feet over the shallow shelf areas of northern Oklahoma and southern Kansas. Because of the very thick sedimentary beds in the deeper part of the basin, the drilling depth record part of the basin, the drilling depth record and/or its producing depth record has been set in this basin several times. Most recently two wells have been drilled below 30,000 feet to hold the present record of the "Worlds Deepest Wells."
The stratigraphic section penetrated in the basin is characterized by unconformities at the top and base of the Pennsylvanian and Mississippian Age rocks.
Investigation of Foamy Oil Effect from Laboratory Experiments
Authors: Urgelli D. , Durandeau M. , Foucault H. , Besnier J -F. 
Published: December 2007

Abstract
The heavy oils from Venezuela and Canada are being considered with a growing interest due to some promising large reserves. From many case histories, the implementation of a cold production scenario has been able to produce this oil at a reasonable cost due to an improved ultimate oil recovery higher than expected. A foamy oil behaviour has been postulated to partially explain the phenomenon.
A series of 5 experiments has been performed to carefully assess the hypothetical foamy oil effect on the ultimate recovery during the natural depletion process. Two parameters were studied: the gravity force impact and the depletion rate in order to upscale these data to the field application. A highly permeable long core was used with heavy reservoir oil (9°API). The porous media was set at initial reservoir conditions (60 bar(g), 49°C) with irreducible water saturation for each of these experiments. The cold production process by natural depletion was implemented at constant depletion rate with an accurate monitoring of the back-pressure regulator.
Comparing laboratory experiments conducted in horizontal or vertical flow direction at low depletion rate, gas gravity segregation effect seems to already improve the oil recovery at the laboratory scale although it is difficult to demonstrate the presence of a continuous gas phase. These results could indicate that the nucleation of the gas bubbles to create a gas phase is a very slow process due to the oil viscosity effect, above 1500 cP at reservoir condition in the presented case. The gas bubbles remain partly trapped within the oil and move with the liquid phase at least up to the threshold saturation. At field scale, corresponding to much lower depletion rate, this effect may be more significant particularly in unconsolidated sands where the vertical permeability is very high.
The ultimate recovery defined at laboratory scale appears to be significantly dependent on the depletion rate as expected and already reported in the literature. It has however to be noted that the mechanism, developed at high rate at the laboratory scale, is not applicable to field production. At low depletion (2.5 bar/d), about 19% IOIP were recovered whereas 42% IOIP were recovered at 12 bar/d and 45% IOIP at 25 bar/d.
The critical pressure at which free gas production occurred was estimated for each experiment. A pseudo 4.5% critical gas saturation was determined for the low depletion rate whereas a high depletion rate yielded 25.5% critical gas saturation.
Hilda Lake a Gravity Drainage Success
Authors: Donnelly John K. 
Published: December 2007

Abstract
Hilda Lake is a steam assisted gravity drainage (SAGD) project. The project consists of one horizontal steam injection well, one horizontal production well and four vertical temperature observation wells. The horizontal wells were directionally drilled from surface and have a horizontal section 900 metres in length. The surface facilities were designed to be low cost and simple to operate. The produced liquids are lifted to surface by the same thermosyphon phenomena that drives a coffee percolator so that no artificial lift is required. Operational procedures have been developed so that down hole monitoring in the horizontal wells is not required. The project was started up on September 5, 1997 and has operated continuously since then. Production results are compared with predictions made with numerical simulation.
Monitoring Steamflood Performance through Fiber Optic Temperature Sensing
Authors: Saputelli Luigi , Mendoza Humberto , Finol Jose , Rojas Luis , Lopez Elias , Bravo Heriberto , Buitriago Saul 
Published: December 2007

Abstract
Improving hydrocarbon recovery from reservoirs needs both a better understanding of fluid flow through the reservoir porous media and new technologies. This paper addresses the later.
Early steam breakthrough, unknown heat distribution and existing exploitation policies inhibit recovery of the remaining reserve of millions of barrels of heavy oil. Integrated reservoir studies and numerical simulations results indicated that proper reservoir management practices such as, reservoir monitoring, heat management, and reservoir characterization can improve final recovery.
In order to better manage heat distribution in heavy oil reservoirs, it is required that vertical and areal distribution of temperature fronts are known.
Permanent well-bore temperature distribution profile was obtained by means of the deployment of a 2,500 ft-long fiber optic cable in two parallel SAGD horizontal wells in Tia Juana field, western Venezuela. A laser bean is sent through the fiber cable and its reflections are collected by a computer, which transforms light reflections into distributed temperature profile information. Distributed temperature profile when compare to resistivity logs easily indicates and correlates which pay zones are being contacted by steam.
Distributed temperature profile information allows reservoir engineers and operators to anticipate which horizons are being swept by steam and which are not. Proper actions on the injection profile can be made in order to improve spatial steam distribution and heat management.
Fiber optics applications also include pipeline monitoring, horizontal well production profiles, electrosubmersible pump monitoring, cross-flow detection, gas lift valve performance, energy management and other general safety application.
Reservoir Management of Mature Oil Fields by Integrated Field Development Planning
Authors: Fabel G. , Neunhöffer T. , Rudschinski D. , Sasse J. , Scheer T. 
Published: December 2007

Abstract
The Rühlermoor oilfield with an OIIP of 110 × 106 m³ (692 MMbbl) has been producing for more than 45 years. Todays production is characterized by low average oil rates, high water cuts and increasing sand problems, which adversely affect the economics. Even after steam drive operations were started 18 years ago to mobilize the viscous oil (120 mPa ⋅ s, 25 °API), total recovery is still less than 25%, leaving considerable potential for additional reserves. With the objective of sustained profitability improvements a comprehensive study was carried out in 1994-1996. Based on re-evaluations of the reservoir, all surface facilities, and the cost structure, various development scenarios were analyzed by a multi-disciplinary team. A number of cost cutting measures were recommended and mostly realized. However, it turned out that a purely cost saving approach would improve the economics only for a short term.
Treatments like frac packs and water shut-off were tested with limited economic success. Cost effective infill drilling (re-entry) was identified as the most economic means to accelerate production and increase reserves in Rühlermoor. By upgrading a field workover rig, total drilling and completion costs could be reduced by 60% compared to a conventional rig.
The key conclusion of the study was that the combination of cost saving measures and production acceleration projects is the only approach to keep the field alive in the longer term.