bluuebunny/crossref_metadata_2025 huggingface dataset:
Waterflooding of A Heavy Oil Marginal Reservoir
Authors: Hanafy H. H. , Mansy A. M.
Published: December 2007

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

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

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

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

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

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.

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.

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

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

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

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

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.
Evaluating Casing Deformation Mechanisms in Primary Heavy Oil Production
Authors: Wagg B. , Xie J. , Solanki S. , Arndt S.
Published: December 2007

Massive sand production during primary heavy oil recovery operations in Northeastern Alberta has resulted in severe deformation of the well casing in a number of wells. A new method for processing multi-sensor caliper data has allowed heavy oil operators to map local casing deformation features such as collapses, buckles and shears that are too localized to be identified with conventional gyroscope surveys. The processed caliper data are used to benchmark numerical simulations of the casing/formation interaction. The formation movements predicted from these simulations are used to infer the geometry of the sand producing zone and can be used to evaluate the effectiveness of a variety of mitigation strategies.
Construction Of Underground Storage Chambers
Authors: Loofbourow R.L. , Wood Wm. G. , Lassiter R.T.
Published: December 2007

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.

Many of the large market areas, near which there is no "natural" storage, can be served from storage in large, deep excavations. We discuss the conditions needed and where they are expected, the appropriate mining plant and methods, the environmental effects, cost and time and the advantages attainable.

Introduction

We are miners. We won't take time to tell you that gas storage is needed near many large markets. You know that better than we. You know the security of conventional underground storage. You know the capital costs and limited flexibility of surface storage and the opposition to it.

We expect you will appreciate the advantage of a storage into which you can put gas and from which you can recover it put gas and from which you can recover it at rates limited only by the design.

We remind you that natural gas has been stored in an unused coal mine north of Denver, in salt cavities in Michigan, Saskatchewan, Texas and Mississippi, and that pressurized butane, propane and ethane liquid and gas are held at more than 60 sites, in underground excavations in many kinds of rock. We believe that none of these storage spaces has any sort of lining. Each type has been in use from 10 to 25 years.

Please remember that the use of underground space is not new. Some of our prehistoric ancestors appreciated its advantages. The first space used was provided by Nature. However the spaces provided by Nature. However the spaces she provides are not always what your public needs nor where they need it. public needs nor where they need it. We shall show you what miners can provide and some of the tools.

BASIS OF MEG CONCEPT

Our concept is bassed on these related coincidences:Strong rock is a fine medium for large stable, low-unit-cost excavations
Natural Gas Supply Situation (May 1975)
Authors: DeLaMater Stephen T.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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.

This paper analyses the factors which will influence the future of gaseous fuels in the United States. The gas industry faces several interrelated problems which have combined both to create the present natural gas shortage and to delay finding solutions to it. The base reason for the shortage is almost universally conceded to be the misapplication of Federal regulation of the wellhead price of gas. Confusing the issue, however, are a general lack of understanding, at the decision making level of government, as to the significance of gaseous fuels to our economy, and a misconception as to the feasibility of alternatives. Discussed are factors which will affect future trends in fuel usage, the importance of natural gas supplementals, the economic impact of an extended severe gas shortage, the need for increased new gas exploration, the availability of new gas supplies, the limitations of the "all electric" argument, and the case for deregulation. This paper concludes that there must be a national imperative for a continuity of our gaseous fuel supply.

IMPORTANCE OF GASEOUS FUELS

The people of the United States, after more than a year and a half of "shortages" and crisis talk, still do not understand the real dimensions of the energy situation. They view the predicament almost solely in terms of predicament almost solely in terms of Mideast oil and its dollar-wise impact on gasoline prices and electricity bills.
Inclination at the Bit Improves Directional Precision for Slimhole Horizontal Wells: Local Case Histories
Authors: Varco Martin , Smith James E. , Stone Dan M.
Published: December 2007

In the 10 years plus of horizontal drilling, productivity improvements and cost reductions have been the result of reducing the hole sizes and geosteering the wells within a specific productive horizon. Drilling programs within the Prudhoe Bay unit (PBU) are targeting thin oil intervals sandwiched between overlying gas and underlying water boundaries. Economic constraints related to the high cost of reaching the reservoir have dictated that each well must access multiple targets over longer horizontal segments. Most of these targets are defined by sealing fault boundaries that produce vertical offset ranging from 10 to 70 ft. Considerable precision in vertical wellbore placement is required to evaluate and then redirect true vertical depth (TVD) placement of the borehole with each fault crossing. Failure to rapidly correct for fault offset produces a low-value horizontal hole. The 4 ¾-in. AIM* At-Bit Inclination Measurement tool, developed for use with an advanced triple combo logging system, delivers directional precision previously possible only in larger hole sizes. This system has been used in PBU to drill complex 3D directional wells, land them to within 1 ft TVD of the required target and then to drill for lengths of over 5000 ft with a similar degree of accuracy. The bit rate of penetration (ROP) of the horizontal section has also increased because the amount of slide time required for wellbore placement corrections is reduced by early detection of steering results using the at-bit measurements.
Inelastic Capture Neutron Logging to Identify Bypassed Hydrocarbon in Complex Secondary-Recovery Environments
Authors: Hupp Douglas , Kasecky Mike , Ohms Danielle , Warner Dwight
Published: December 2007

Inelastic capture neutron logging (IC) has been used successfully to identify water influx and by-passed hydrocarbon in the mature oil fields located on the North Slope, Alaska. The North Slope has had commercial production since 1977. Production from these fields are enhanced by secondary recovery techniques including water flooding using Beaufort Sea and produced water, natural gas re-injection and miscible fluid injection techniques. The uses of traditional cased-hole evaluations (sigma and porosity interpretation from pulse neutron and cased hole neutron logs) are limited due to the complexity of the secondary recovery techniques including wide variations in the salinity of injected water. Beaufort Sea water salinity varies widely through out the year due to the influx of fresh water during the spring run off. Inelastic capture neutron logging and interpretation has allowed identification of remaining and by-passed oil and has aided in the planning of sidetrack wells to tap additional reserves. Ambiguities arising out of formation water salinity uncertainties have been clarified through the use of inelastic capture neutron logging techniques.
Acid-Sludge: How Small Particles Can Make a Big Impact
Authors: Rietjens Marcel , Nieuwpoort Marco
Published: December 2007

Acid-induced sludge, a major source of well damage, can vary from a viscous, stable emulsion to the product of a polymeric reaction. This paper examines the nature of sludge and how it is formed.

Sludge particles are often believed to be large, but research shows that the molecular weights of the constituents of sludge particles are relatively low. In size-exclusion chromatography tests, sludge was dissolved in a solvent and analyzed. Results showed that the mass of sludge constituents was only twice that of the highest molecular weight of the oil components. In undiluted pure oils, however, sludge particles were much larger than particles of the constituents; individual sludge particles are even visible by microscopy.

A chemical analysis of sludge shows that hydrochloric acid (HCl) is present in the sludge structure but water is not. Besides HCl, Fe(III) ions in HCl formulations can cause a large amount of sludge. Even though ferric ion could not be detected in the oil phase or in the sludge, it induces sludge mainly because it works as a phase-transport catalyst for HCl.

Sludge is an aggregate of protonated molecules. Aggregation is initiated by protonation of asphaltenes and other compounds, such as resins, that undergo acid-base interactions. Molecules are then formed that have surfactant-like properties that tend to form structures resembling reversed micelles. Stack formation, which occurs in asphaltene aggregation, is another initial mechanism for aggregation of protonated constituents. These initial aggregates eventually become a flocculate, or sludge.

The aggregation theory seems to be supported by the fact that a critical aggregation concentration exists, below this concentration level, sludge will not form; above this concentration level, sludge is formed in increasing amounts.

This paper shows that sludge can be dissolved in pure solvents or in nonsolvents containing surfactants, demonstrating that sludge formation is reversible.
Production and Cost Optimization for Sand Control Completions over Thick Reservoir Sections: Application to Two Fields in West Africa
Authors: Petit G. , van Domelen M. L.
Published: December 2007

Selecting the optimum sand control technique for reservoirs with large vertical thickness and long wellbore lengths through the pay zone is currently a topic of widespread discussion in the industry. The selection is made by comparing the expected productivity of the completion procedure with the cost. The decision is made difficult because some very important reservoir parameters such as permeability, damage, oil properties, and layering sometimes only become known during the completion phase.

This paper gives the overall results of fourteen producing oil wells that were completed in two offshore fields in West Africa using the frac-and-pack sand control technique. The wells had deviations of up to 61°. These wells have moderate production levels (around 2,000 bopd/well) and have multiple layers, spread over 200 to 350 ft gross interval lengths. One aspect of this paper will be to describe the efforts made to quantify the relative costs between various sand control techniques, taking into account such factors as material costs, rig times, and equipment requirements, and how these cost assessments were then weighed against expected completion efficiencies.

When designing the treatments, some important guidelines were also established regarding how to group layers together for a single treatment, how to open the perforations before the frac treatment, how to model fracture growth in these deviated wells with possibly more than one interval perforated, and the actual completion procedure. A review of the different well results is presented with the objective to better understand the impact on the productivity of different factors such as deviation, interval length, completion and sand control practices.
Effect Of Porosity On Depth Of Investigation Of Neutron And Density Sondes
Authors: Sherman H. , Locke S.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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.

Depths of investigation of a Density tool and several versions of Neutron tools hate been measured experimentally at a porosity of 22 percent in quartz sandstone. Comparisons with earlier results in 35-percent-porosity sandstone indicate little change in depth of investigation over this porosity range. The results also illustrate dependence of depth of investigation on casing and cement, neutron-source energy, relative change in hydrogen content, and presence of thermal-neutron absorbers. presence of thermal-neutron absorbers.
History of Development of the Tijerina-Canales-Blucher (Zone 21-B) Field High Pressure Extension Area
Authors: Harris Gregg A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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.

This paper presents (1) the results of a combined engineering/geological study that led to the discovery of several million barrels of additional oil in the nearly 30 year old Tijerina-Canales-Blucher (21-B) Field oil column; (2) the results of a two-dimensional, three-phase computer simulation study of the reservoir; and (3) a comparison of actual versus predicted performance. The new oil area was discovered in late 1972 by drilling Exxon's King Ranch-Tijerina Well A-29 to investigate a possible stratigraphic trap suggested by an observed anomalous high pressure area. Twenty additional wells were drilled before extent of the new oil area was known. A computer model simulator study was made to predict future performance, to determine an predict future performance, to determine an optimum water injection program, and to determine if producing rates were compatible with maximum oil recovery.. The oil reserves are now essentially depleted and a favorable comparison can be made between actual and predicted performance. Additional oil reserves predicted performance. Additional oil reserves developed in the high pressure extension area are estimated to be 3.9 million barrels. Fifty-two percent of the oil in place will be recovered, and a volumetric sweep efficiency of 85 percent is indicated.

Introduction

The Tijerina-Canales-Blucher (21-B) Field is located about 12 miles southwest of Kingsville in South Texas. As shown in Figure 1, this field is situated at the southern end of the Zone 21-B Trend Field, which consists of a large gas cap with several rim type oil columns. Prior to 1975, the Zone 21-B Trend Field had been prorated by the Texas RRC as three separate fields-Borregos, Seeligson, and T-C-B Fields. The T-C-B oil column, which was discovered in 1944, is located along the southern and eastern rim of the structure and was developed by drilling in the 1940's, 1950's, and 1960's. Exxon developed its portion of the oil column with about 110 wells on 40-acre spacing.

The 21-B sand in the T-C-B field is located at an average depth of 7,000 feet subsea and is composed of four sand stringers which are in communication with one another in certain areas of the T-C-B field. Sand quality is good as porosity averages 25 percent and permeability averages 186 mds. percent and permeability averages 186 mds. Primary drive mechanism is gas cap expansion Primary drive mechanism is gas cap expansion which has been supplemented by gas and water injection.
Physical Observations and Mapping of Cracks Resulting from Hydraulic Fracturing In Situ Stress Measurements
Authors: Tyler L.D. , Vollendorf W.C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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.

For many years hydraulic fracturing has been used as a stimulation tool for oil and gas reservoirs. Hydraulic fracturing has also been developed as a method to measure in situ stresses. The correspondence between the measured fluid pressures and the in situ stresses has been studied and is fairly well understood. The characteristics of the fractures created by hydraulic fracturing are not understood. Information about the fractures at the wellbore can be obtained by a number of techniques but knowledge of the fractures behavior away from the well is very limited. The fracture behavior may determine either the stress direction for a stress measurement or the difference between a good or bad stimulation job.

To better understand the hydraulic fracture technique, experiments were performed in a tuff formation in Rainier Mesa performed in a tuff formation in Rainier Mesa at the Nevada Test Site. The purpose of the experiments was to determine the stresses in the mesa; and, to examine the fracture behavior produced by the hydraulic fracture technique. Hydraulic fracturing was performed in both vertical and horizontal performed in both vertical and horizontal boreholes with a maximum overburden of 1490 ft. All experiments were done in the vicinity of an existing tunnel complex but sufficiently remote to avoid unwanted boundary effects. The stresses were determined from the hydraulic fracture data using the theory of Fairhurst and Haimson. The maximum horizontal, vertical and minimum horizontal principal stresses for 1365 ft. of overburden principal stresses for 1365 ft. of overburden were 1788 psi, 1183 psi, and 1015 Psi, respectively. A number of the fractures produced during the tests were mapped by produced during the tests were mapped by mining from the tunnel complex and physically examining the fractured formation. physically examining the fractured formation. Dyed water was used for all the holes drilled in the tunnel complex. Dyed cement grouts were used to tag the fractures formed in a 1365 ft. deep hole from the top of the mesa. Two fracture jobs were performed at two locations in the vertical hole using yellow and red grouts. These fractures were essentially vertical and parallel.
A Heuristic Approach to Drilling Optimization
Authors: Tansev E.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper presents a new approach in formulating and solving the optimal drilling problem. The approach is heuristic as it involves the interaction of raw data, regression and an optimization technique. From several bit runs regression equations were established for predicting penetration rate and bit life. Three control variables are accounted for: weight on bit, rotary speed and bit hydraulic horsepower. The equations for penetration rate and bit life are incorporated into a drilling cost equation and the cost function is minimized over the control variables. These variables then dictate the optimal drilling of the next bit run.

A uniform formation drilled with similar bits and an on-line optimization scheme for updates with each new bit run, is best suited for this approach. An application of the procedure to field data is given.

Introduction

Numerous publications over the years have contributed to the complex subject of drilling optimization. Concentrating on some of the recent publications that offer a mathematical model for drilling, publications that offer a mathematical model for drilling, Reed devised a Monte Carlo technique to solve the variable weight-speed problem. He concluded that it offers very little advantage over the simpler constant weight-speed approach. He then presented a solution to the constant weight-speed problem based on the conjugate-gradient method. Reed used nearly the-same set of empirical equations Young proposed, as a set of differential constraints in the context of minimization. Interestingly we found no significant difference in comparing several examples reported by Reed with solutions by Young's formulation. Wilson and Bentsen applied several optimization techniques to minimize drilling costs. In their "Multi-interval Optimization", dynamic programming was used to optimize the intervals drilled and programming was used to optimize the intervals drilled and the minimum of the total cost function indicated where to change the bit. They have used the equations derived by Galle and Woods in their modeling. Some theoretical analysis that include the stress properties of the formations was carried out by properties of the formations was carried out by Wardlaw. Polynomial-type functions were derived from dimensionless groupings of variables according to categorized drilling conditions. Minimization of the drilling cost function was achieved by geometric programming. programming. There appear to be some drawbacks in common to each of these approaches. These can be listed as:Several formation and bit parameters must be known in advance. These are determined from analytical expressions, from previous data, field testing or from experience and judgement;Only bit weight and rotary speed are fully accounted for as control variables.
Review of Thermal Recovery Methods
Authors: Dietz Daniel N.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Oil displacement is less than perfect because despite driving forces - part of the original oil in place is retained by capillary and by viscous forces. The viscous forces can be reduced by heating the oil in place. Most of the heat is inevitably taken up by the oil sand, interbedded shales and cap- and base rock. The heat is therefore used most efficiently where a maximum of thermally recoverable oil is tied to a minimum of rock (heavy oil, high porosity etc.). The economy may be improved by recuperating heat from swept formation for repeated use.

Besides reducing the retaining forces, thermal drive also enhances the driving forces because many reservoir volumes of hot water, steam or air are required to displace one volume of oil. For steam and air this enhancement is stronger the lower the pressure.

In the initial phase, when the oil is still cold, it may be hard to obtain satisfactory circulation and special well patterns with a high number of producers per injector (inverted 9 spot, 13 spot) are sometimes used. These patterns also minimize pressure later on. Heat stimulation of producers is also used to facilitate start up. producers is also used to facilitate start up. Where heat recuperation is applied, the recovery-efficiency of the heat should also be considered and an overall sweep from the reservoir boundary may be preferred over a pattern flood.

The heat may be applied from the surface by specially designed hot water heaters or steam generators. The injectors are subjected to high thermal stresses and in old fields, where more often than not additional wells have to be drilled, the new ones are invariably used as injectors.

The compressed air for in situ combustion requires more expensive surface installations, but less fuel than hot water or steam. Heat recuperation is more efficient in combustion projects because it can be done continuously projects because it can be done continuously by simultaneous cold water injection. Wet combustion, with its double injection system requires more engineering than any other thermal drive: determination of optimum water/air ratio, evaluation of corrosion danger and where necessary its prevention.