bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Development of Heavy Oil Fields in the U.K. Continental Shelf: Past, Present and Future
Authors: Jayasekera A. J. , Goodyear S. G. 
Published: December 2007

Abstract
Historically, most UKCS production has been of light oil, 300 API and above. However, since 1993, a number of heavy oil fields have been brought on production. This paper reviews the history of UKCS heavy oil, the challenges overcome to bring these fields to development, and the future outlook.
The occurrence and distribution of the UKCS heavy oil in place is discussed. A specific correlation to estimate reservoir viscosity from API gravity is presented. Productivity of heavy oil reservoirs is compared with light oil developments, different categories of heavy oil reservoirs are identified, and the use of horizontal or multilateral well technology to achieve acceptable production rates is discussed. The implication of well productivity testing (e.g. extended well testing) of appraisal wells is discussed.
The development challenges that have been overcome in current developments (Harding, Gryphon, Alba, Captain) are reviewed, in particular focusing on well productivity, pressure support, recovery efficiency (management of gas and water coning, areal sweep), and oil water separation. The paper will also review the cost and risk management strategies that need to be adopted to enable the economic exploitation of these heavy oil resources in a demanding environment such as the UKCS.
Finally, the potential for future heavy oil developments is discussed. The scope for IOR technology to increase reserves in heavy oil fields on production by waterflood, or to improve the economics of currently sub-economic fields, is reviewed, focusing on advanced well technology, downhole separation, thermal techniques and conformance control methods.
Non-Darcy and Multiphase Flow in Propped Fractures: Case Studies Illustrate the Dramatic Effect on Well Productivity
Authors: Vincent Michael C. , Pearson C. Mark , Kullman John 
Published: December 2007

Abstract
The dramatic effects of non-Darcy and multiphase flow in propped hydraulic fractures have been documented by several authors.1,2,7,9-19 However, many engineers disregard these effects when designing fracture treatments under the assumption that they only apply to high rate wells. This paper shows these effects are significant even in wells considered to be low rate by current industry standards. Ignoring these effects will often lead to inaccurate production forecasts, suboptimal fracture design, and selection of an inappropriate proppant type. These mistakes result in lost revenues which can exceed $2 million per fracture treatment for typical gas and oil well fracture treatments conducted in North America.
Proppant permeability values reported by the industry and used in most fracture design models are measured with a single-phase fluid at extremely low velocities. The laboratory rates stipulated in the American Petroleum Institute3 (API) Recommended Practice number 61 typically correspond to superficial fluid velocities ranging from 0.2 to 2.0 inches per minute. However, in real fractures, the actual fluid velocity may exceed two feet per second, approximately 1000 times greater than in the laboratory measurements. Although the API warned that the lab-measured values would not be realistic under actual fracture conditions, the industry has largely failed to incorporate correction factors into production models to compensate for non-Darcy flow effects.
In addition to non-Darcy effects, the measured proppant permeability values fail to incorporate the effects of multiphase flow. Most gas wells will produce some free liquid (water or condensate), and almost all oil wells will be produced below the bubblepoint of the oil, resulting in substantial volumes of free gas in the fracture. This paper shows that non-Darcy and multiphase flow effects frequently result in an effective fracture conductivity 50% to 98% lower than the reference value obtained from the API testing procedure. Incremental reductions for gel damage and proppant embedment often result in fracture permeabilities or conductivities (the product of fracture permeability and effective fracture width) of 1 to 10% of the published values. This paper examines the mistakes that are likely to be made when ignoring these effects, and estimates the additional cashflow which can be obtained by optimizing fracture design with consideration of multiphase and non-Darcy flow.
Damage-Specific Stimulation Techniques Provide Maximum Deliverability Improvement in Four Gas-Storage Reservoirs—A Case Study
Authors: Guoynes John , Azari Mehdi , Squire Ken , Blauch Matt , Gillstrom Bob , Stegent Neil , Durey Daniel , Jestes Chad , Bielecki Don , Yater John , Clark Randy , Frame Russ , Hopps Kenneth 
Published: December 2007

Abstract
Research has shown that the proper identification of damage mechanisms can improve stimulation techniques used to enhance deliverability in gas-storage wells. The damage mechanisms must be identified before the highest-potential candidate wells and their most effective treatments are determined. Additional data analyses are required to rank candidates properly and design specific treatments to maximize deliverability. Once the diagnostic data are collected and analyzed, an operator must apply the relevant data analysis to the selection of one or more tailored, effective treatment designs. Since many storage companies work from a fixed treatment budget, an adequate well-ranking process must be used for maximum deliverability of dollars spent. The wellranking process can reveal various options for enhancing deliverability with different treatments.
This paper presents case studies from an alliance project in which over 60 wells were diagnosed, treated, and evaluated in four gas-storage reservoirs. Comprehensive diagnostic analyses allowed the development of damage-specific stimulation treatments. New, rigorous processes were developed to evaluate damage and select appropriate treatment options
In this study, damage mechanisms were identified through the use of methods described in a previous Gas Research Institute (GRI) project. Formation damage in each well was quantified by well-test analysis and historical injection/withdrawal-cycle performance matching. Log analysis, petrophysical data, geological data, wellbore imaging, and historical workover data were also gathered as diagnostic treatment-design criteria. The deliverability improvement was quantified for each well based on post-treatment diagnostics. Each study uses several unique treatment options that address a variety of formation damage mechanisms. Treatments were selected to produce the highest deliverability enhancement and maximize the operators’ investment returns.
In Case Study 1, high-pressure jetting, acidizing, and hydraulic-fracturing techniques were used in a deep high-permeability pressure-drive carbonate reservoir. In Case Study 2, high-pressure jetting and damage-specific fluid treatments were used in two shallow-water-drive clastic reservoirs. In Case Study 3, hydraulic fracturing, high-pressure jetting, and extreme overbalanced perforation (EOP) surging were used in a shallow highpermeability pressure-drive clastic reservoir.
Modification of Two Phase Flow Properties by Adsorbed Polymers and Gels
Authors: Zitha Pacelli L.J. , Vermolen Fred J. , Bruining Hans 
Published: December 2007

Abstract
A model for the flow of water and oil in granular porous media treated with polymer and gels is presented. The pore geometry is represented by a triangular duct with a periodically varying section while the topological features are modeled by a statistical network. The mathematical treatment consists of the solution of the hydrodynamic equations in the duct and the up-scaling by a percolation type of approach.
The relative permeabilities of a wetting (water) and non-wetting phases (water and oil or gas respectively) are derived both (a) in the absence and (b) in the presence of the an adsorbed polymer or gels. The preliminary results show that both the flow restrictions at the pore level and the topological changes resulting from polymer adsorption or gel retention contribute to the disproportionate permeability reduction (DPR) for water and oil.
A more systematic study of the effects of the parameters and the comparison of the model with the experiments are required for a full validation of the model.
Utilization of Sand Control and Mechanical Profile Control in Numbi Field Water Injection Wells
Authors: Needham W. J. , Gross S. J. , Pape W. C. , Wilson B. A. 
Published: December 2007

Abstract
The Numbi field is located approximately 20 miles offshore of the Cabinda enclave of Angola. The main producing reservoir in the Numbi field, the 57-05 Upper Vermelha reservoir, is comprised of a stacked sequence of near shore deposits approximately 550 FT thick. The reservoir is highly stratified and faulted, containing a hydrocarbon column that consists of a 200-FT thick oil column overlain by a 240-FT thick gas cap.
The field was discovered in 1982 and placed on production in 1987. A peripheral waterflood project was implemented in 1991 to maintain the reservoir pressure and to improve the ultimate oil recovery. The field reached a peak production rate of over 85,000 BOPD after water injection was initiated. However, poor injectivity, formation sand back-flow into the injection wells, and poor injection profiles prevented the desired level and distribution of water injection from being achieved. These imbalances in injection caused gas cap expansion in some areas, and oil migration into the primary gas cap in others.
Cabinda Gulf Oil Company recently implemented fundamental changes to the reservoir management strategy of the Numbi field to maximize the field's ultimate recovery. Crestal waterflood injection wells have been drilled into the gas cap to balance the distribution of water injection, to increase the voidage replacement ratio (VRR), and to serve as a buffer to prevent the migration of oil into the gas cap. The new injection wells have been successfully completed as screenless frac packs employing curable resin-coated proppant (RCP) for sand control and incorporating multiple packers with injection mandrels for mechanical injection profile control. Pre-job laboratory evaluations were performed with manifold objectives including selection of the optimum curable RCP to be compatible with the proposed fracturing fluid. This was done to provide a frac pack with the greatest conductivity and sufficient compressive strength to withstand the impacts of stress-cycling due to periodic water injection shut-downs. Three dimensional fracture simulations were used to optimize the fracture geometry during the design and implementation of the frac-packs. While the evaluation of the success of these completions is ongoing, results thus far show that the target injection rates are being achieved and that the injection profiles are balanced. The success of this well design is critical for achieving the reservoir management objectives at Numbi.
Kill Procedures to Avoid Formation Damage in the High Rate Gas Wells of an Underground Storage Project
Authors: Oudeman P. 
Published: December 2007

Abstract
To meet winter peak delivery obligations, a depleted gas field in the North Netherlands was converted to a storage reservoir. The 7 5/8″ mono-bore wells were designed for high production and injection rates, up to 280 MMscf/d (8 MMsm3/d) per well from the fully charged reservoir. To produce at such high rates any damage to the formation has to be avoided. A particular concern in this respect was killing the wells e.g. prior to a work-over or in case of an emergency. Inclusion of a side pocket mandrel to land a down-hole circulation device, a potential leak path, was considered undesirable in the design for the high-pressure wells. Hence the wells were to be killed by bullheading. This technique however bears the risk of damaging the productive formations when plugging material is forced into the rock. Therefore it was investigated how the bullheading process could be controlled so that all the gas is pushed back into the reservoir, while avoiding the invasion of foreign material in the productive formations. A dedicated field test to demonstrate the feasibility of the technique was carried out. This test, results and analysis will be discussed.
Particulate Invasion From Drilling Fluids
Authors: Bailey Louise , Boek Edo , Jacques Simon , Boassen Tony , Selle Olav , Argillier Jean-Francois , Longeron Daniel 
Published: December 2007

Abstract
Particulate invasion is one of the primary mechanisms of formation damage caused by drilling fluids. During the initial stages of filtercake growth particles are forced into the formation, building an internal filtercake which plugs the near surface pores. Where bridging is inadequate, the depth of invasion can be considerable. Removal of this internal cake can be difficult, leading to reduced productivity. Better understanding of its properties will lead to more effective cleanup and enhanced productivity.
As part of an EC-Joule funded study into formation damage mechanisms, we have investigated both the invasion of solids and their mobility during clean up. We have systematically investigated the effect of mud particle size on rock substrates of varying permeabilities. The results indicate that formation damage increases with increasing substrate permeability. Substrate permeability was also found to have a marked effect on the initiation of production; flow initiation pressures were greatest on low permeability cores.
Quantitative profiles of solids invasion into sandstone cores for a range of water-based drilling fluids were obtained using scanning electron microscopy/ X-ray mapping (SEM-EDS) and synchrotron energy-dispersive X-ray diffraction tomography (EDD-T). This latter technique, using a synchrotron source, samples the intact core rather than a fractured surface, and gives analytical powder diffraction data, whereas a conventional CAT scanner provides attenuation data only. The effect of back flooding on the invasion profile was then examined, and permeability damage associated with the invasion was also determined. The invasion was compared to damage profiles obtained by core sectioning. Invasion profiles were found to drop quite steeply but fines could be observed deep with in the core. The presence of external cake was found to influence the ease of clean up of the invaded zone.
A deep bed filtration model has been developed for the effect of solids invasion on permeability reduction. This model is compared to the profiles obtained in the invasion experiments.
Core-Flow Experiments With Oil and Solids Containing Water
Authors: van den Broek W. M. G. T. , Bruin J. N. , Tran T. K. , van der Zande M. J. , van der Meulen H. 
Published: December 2007

Abstract
This paper describes core-flow experiments with sandstone cores and artificial produced water. The water contained small quantities of solids in the form of ground sandstone, of oil in the form of droplets, or both solid particles and oil droplets. In the case of water with solid particles the parameters having the largest influence were particles concentration and, to a lesser extent, size. Usually a considerable decrease of the permeability of the first section of the core was observed after an amount of a few hundred pore volumes was injected. For a relatively low particle concentration, in combination with a relatively small average particle size, this decrease was less severe. Injection of water with only oil droplets eventually led to a small permeability decrease in all core sections. Also for injection of water containing both oil droplets and solid particles, the particles concentration appeared to be the most influential parameter. Here the presence of oil usually led to some additional permeability decrease.
Coal Analysis From Well Logs
Authors: Kowalski John J. , Holter Milton E. 
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.

Abstract
Well logs can provide an analysis of coal which is comparable to core analysis through the use of new interpretation methods which were developed for use in the United States, Canada and Europe. By using well logging methods, two problems encountered in core analysis are reduced. The answers are available in a very short period of time, there are few storage problems.

Introduction
Log evaluation of coal is not a new concept. One of the early applications of well logs was to delineate coal seams in Europe. However, a more economical, cleaner, and more versatile energy source was found in crude oil, and wireline geophysical techniques were primarily adapted to evaluation of this resource. In the past 10 years, an increased interest in coal led to the development of log evaluation techniques using devices designed for petroleum applications.
The first technique that was developed used an Acoustilog and Densilog combination which could be supplemented with neutron and resistivity devices. This system had several limitations most important of which was hole size. Many coal companies take about 2-1/2" diameter cores (open hole diameter is 4") and logging devices are usually larger than this. Drilling the larger holes adds a considerable amount to the cost. A second objection was that there were few oil wells drilled in coal areas which fit this particular combination of logs so very few oil well recordings would be usable in the coal evaluations. In 1974, Dresser Atlas developed a method which utilized two logs, the Induction Electrolog and Densilog which are frequently encountered in the petroleum industry. This method was later modified to accommodate three other combinations of services.
The techniques used in the past to evaluate coal seams consisted of coring the seams and doing a laboratory analysis of the core for carbon, ash, and moisture. Two major difficulties are encountered with this method. The first is keeping the core in its original condition so that the analysis of the data reflects the true condition of the coal. The second problem occurs when core recovery is poor or whenever the coal is drilled into before the commencement of coring. Both of these problems can lead to a poor evaluation of the reserves, however, well logs offer a solution to them.
Jay-Lec Waterflood Pattern Performs Successfully
Authors: Shirer J.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.

Abstract
Early waterflood performance in the Jay-LEC Fields indicates that the 3:1 Staggered Line Drive pattern is operating successfully. The rapid reservoir pressure decline has been completely arrested and the oil allowable of 93,500 STB/D has been maintained. The waterflood was initiated in March, 1974, and is expected to increase ultimate oil recovery by more than 200 million STB.

Introduction
The large oil accumulation in the Jay-Little Escambia Creek Fields located in northwest Florida and southern Alabama was discovered in June, 1970, and production was initiated in December, 1970. However, reservoir pressure declined rapidly along with additional development and withdrawals. Low ultimate oil recovery and early loss of well capability were eminent.
A 3:1 Staggered Line Drive pattern was selected to initiate a waterflood program after comparative evaluations using a two-dimensional reservoir simulator model indicated that the highest oil recovery and economic potential would be realized. The necessary equipment was installed to service the 3:1 pattern concurrent with field development and unitization. Water injection was initiated on March 5, 1974, four days after the effective date of the Unit.
This paper presents a summary of early waterflood performance which indicates that the 3:1 Staggered Line Drive pattern is operating successfully. The rapid reservoir pressure decline experienced during primary pressure decline experienced during primary operations has been completely arrested by injecting 180,000 BPD of fresh water and the oil allowable rate of 93,500 STB/D has been maintained. Volumetric sweep efficiency appears to be satisfactory since injection water breakthrough has occurred in only two of the 65 oil wells. In each case, breakthrough was predictable and a result of limited, nonrepresentative flood conditions.
Ultimate oil recovery from the Jay-LEC Fields should be increased by more than 200 million STB as a result of a successful waterflood program.

RESERVOIR DESCRIPTION

Geology
The primary oil accumulation in the Jay-LEC Fields is located in the upper Smackover formation. Figure 1 is a structure map contoured on top of the Smackover. Structurally, the reservoir is a southeast plunging nose uncomplicated by faulting.
Synergism in Thickened Water Systems for Improved Oil Recovery
Authors: Norton Charles J. , Falk David O. 
Published: December 2007

Abstract
Synergism is demonstrated among several bicomponent water soluble polymer systems used to thicken water for improved oil recovery. Extensive screening experiments indicate viscosity and screen factor synergisms are unpredictable from chemical nature and structure of the polymers. In some cases screen factor synergism carries over to improved oil recovery in Berea core floods under Maraflood TM process conditions. Several synergistic polymer systems offer potentials for economic savings and potentials for economic savings and operational flexibility together with improved oil recoveries under both secondary and tertiary flooding conditions.

Introduction
Our attention is largely directed toward tertiary recovery systems using the Maraflood process. This paper summarizes our laboratory investigations and results with bicomponent water-soluble high molecular weight polymer mixtures for improved oil recovery under enhanced recovery conditions.
A review of the literature suggested the potential of significant synergism in viscosity. We were impressed by the disparity between the viscosity and screen factor measurements in some systems and decided to give more weight to the latter measurement. We found that screen factor measurement is a useful screening tool that has led us to a number of synergistic systems which give improved oil recovery under laboratory conditions. Studies of many systems indicated that screen factor synergism in bicomponent polymer systems is very rare, unpredictable and not directly correlated with the chemical nature and structure of the polymers under investigation.

EXPERIMENTAL
REAGENTS. Materials investigated are summarized in Table 1. Viscosities and screen factors were determined in deionized water and a soft water formulation (Palestine water).