bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Focus Development for Heavy Oil Reservoir: The Last Frontier At the South Belridge Field
Authors: Chiou C. S. , Badger S. D. , Carlsen M. M. , Pereira K. S. 
Published: December 2007

Abstract
The Tulare reservoir of the South Belridge field, CA has been under steam drive since the 1970s. A variety of field development opportunities remain in the southern portion of the field. Over the past two years, Aera Energy has implemented a focus development project to execute the growth strategy for the field. To date, 60 horizontal and 70 vertical producers and 120 steam injectors have been drilled and completed in a 640-acre area. This paper focuses on development strategy, development optimization using reservoir simulation, economic evaluation, and development implementation.
Reservoir modeling has been proved to be a powerful tool for (1) assessing alternative development strategies between horizontal and vertical wells for a multi-sand reservoir, (2) planning optimum pattern configuration and well spacing, and (3) assessing reservoir performance impacts of various operating policy options.
Production Optimization Using a Dynamic Gas-Lift Simulator, History Case
Authors: Muñoz Efrén A. , Quintero Nylian 
Published: December 2007

Abstract
Gas injection is a very popular artificial lift method, at present a very high percentage of wells produce under this mechanism, hence it is very important to understand all operational and practical effects that are associated when an oil well is producing under gas-lift. Its optimization is critical to maximize oil production using the optimum amount of gas required and to justify the use of this technology as nowadays other artificial lift methods are very efficient too. Although, commercial softwares can simulate a gas-lifted well, all of them consider steady-state conditions, however the injection of gas through orifices or valves is a totally dynamic situation1.
This paper shows some real examples where the use of a dynamic simulator was necessary to understand both well behavior and model simulation specifically when trying to optimize wells producing under unstable conditions.
The generation of realistic performance curves under those circumstances becomes critical, as they are the bases of any gas-lift optimization project as shown in this paper.
A Field Application of Lateral Drilling from an Existing Well for Improved Recovery in Low Permeability Sands
Authors: Bigno Y. , Coombes T. , Lheure S. 
Published: December 2007

Abstract
The Dunbar Field, lying in the East Shetland Basin in Block 3/14a (U.K.C.S.), contains a significant proportion of its volatile oil in thick (90 m), low permeability sands (1-2 mD) of the Brent Group/Upper Massive Sands. To achieve secondary recovery from these ‘tight’ formations, high productivity horizontal or multi-lateral drains had to be designed as withdrawal points. The drilling of such wells in a highly compartmentalized and complex reservoir was not without significant risk, particularly in relation to the known levels of lateral and vertical heterogeneity.
An early development well, D05, originally planned as a water injector, provided an opportunity to evaluate the benefits of such horizontal drains within the ‘tight’ zones. This vertical well also contained thin, high permeability (100 mD) layers below the thick low permeability ‘Upper Massive Sands’. A lateral drain (D05Z) was planned within the Upper Massive Sands whilst the original vertical hole would be retained. The two sections would be completed in order to produce from both the permeable and ‘tight’ zones.
This paper presents the full process of the evaluation of the pre-drill vertical well and the reservoir studies that followed. These studies led to the recommendation to drill a lateral drain of very complex geometry while retaining the production from the existing vertical section. The 960 m lateral drain that was subsequently drilled complied with very strict recommendations and guidelines and constituted a major drilling achievement. The production performance of the lateral drain was also a success and increased Total and Elf's confidence in the use of such complex wells (horizontal, dual drains, multi-lateral drains). In fact, they are now the chosen option for the development of the Dunbar tight zones.
Strategy Optimization for Matrix Treatments of Horizontal Drains in Carbonate Reservoirs, Use of Self-Gelling Acid Diverter.
Authors: Bazin B. , Charbonnel P. , Onaisi A. 
Published: December 2007

Abstract
Matrix treatments of horizontal drains in carbonate reservoirs require large amounts of acid, leading to economic-cost and pumping-time considerations. Therefore it is essential to improve candidate selection and to optimize treatment design, especially acid volume, placement and diverting technique.
This paper discusses first, on a theoretical basis, the formation damage effects on horizontal well productivity. Hence, a stimulation strategy is being defined.
The effectiveness of a Self-Gelling Acid Diverter (SGAD) is evaluated by screening the crosslinking conditions with single core flow tests. In particular, the effects of the acid strength in both the diverter stage and the neat acid stage are scrutinized. The diverting effect is also analyzed with a dual core flow apparatus specially designed to reproduce down-hole injection conditions in horizontal wells. The efficiency of the self-gelling agent is evaluated from fractional flow measurements and X-Ray CT visualization of the wormhole penetration. Finally, the study is completed with radial core flow experiments, previously damaged with a drilling fluid.
Design and operational guidelines are deduced from the experimental results and a case history is presented.
Prediction of Wormhole Population Density in Carbonate Matrix Acidizing
Authors: Huang T. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
The efficiency of a carbonate matrix acidizing treatment relies strongly on the dominant wormhole channels formed during the treatment. We have developed and confirmed a theory to predict when the dominant wormhole channels are most efficiently created. Based on this theory, a wormhole population density model was developed.
In a carbonate acidizing treatment design, the acid volume needed to bypass the near wellbore damage area or penetrate a distance away from the wellbore depends not only on wormhole propagation distance but also on how many wormholes are created. This study investigates the wormhole population density, which means how many wormholes per area of rock surface or per wellbore length will be created. The study is based on the following strategy. For a given rock/acid system, the optimal acid injection flux at which dominant wormholes are initiated is obtained from the wormhole propagation theory. For a given formation, a corresponding pressure gradient at the optimal acid flux is calculated. This pressure gradient is also called the wormhole initiation pressure gradient. When a wormhole is initiated at an arbitrary point along the wellbore, the local pressure distribution is disturbed, resulting in lower pressure gradients into the formation in the region surrounding the wormholes. In this region of reduced pressure gradient and hence, reduced flux, initiation of other wormholes is suppressed. At a sufficient distance from the initial wormhole, the pressure field is undisturbed and other wormholes will develop.
We numerically simulated the flow field around a wellbore with a wormhole extending into the formation to quantify this phenomenon. From this study, we predict the wormhole population density along a wellbore as a function of the acidizing conditions. An example is provided to show the application of the wormhole population density model in a treatment design. Fluid loss through the walls of the wormholes and wellbore, optimal acid injection flux, and wormhole propagation rate are also taken into account in this example. The example shows how the wormhole population density model is used to predict the required acid volume (gal/ft) to yield the desired productivity improvement.
Permeabilities and Skins in Naturally Fractured Reservoirs: An Overview and an Update for Wells at Any Deviation
Authors: Lietard Olivier 
Published: December 2007

Abstract
Though matrix and secondary porosity permeabilities of a naturally fractured reservoir are generally well-known since the work of Muskat (1949), notions of skin remain extremely vague to a majority of reservoir engineers. This paper aims at alleviating a problem which considerably impairs the understanding of such complex reservoirs.
A detailed mathematical study, similar to Muskat's, is first presented as a reminder of his equation giving the permeabilities of a rock with no primary porosity and a pattern of natural fractures, either conjugated (two parallel systems at an angle) or not. The same tool is then used to demonstrate that a vertical well connected to the natural fractures does show up a negative skin, which is a simple function of the well radius and the spacing of the fractures.
The Hawkins’ definition of (positive) damage skin is then applied to vertical wells. Both a "missed target" skin (well not connected to the fractures) and a fracture invasion damage skin (by drilling mud or heavy ends deposition) are defined. The missed target skin explains why Dennis Beliveau's Productivity Improvement Factor is much better in naturally fractured reservoirs. The mechanism of mud invasion into fractures is reviewed and the related skin calculated as a function of the mud loss volume per unit of drilled length.
Though Hawkins’ skin can also be defined in deviated wells (as Renard and Dupuy did in horizontal ones), the partial completion skin approach (e.g. Brons and Marting's) is shown to be more applicable after production has been initiated. Such a skin is calculated as a function of the number of fractures connected to the well at any time, and of their spacing in the reservoir.
Completion Efficiency Measures for High-Permeability, Unconsolidated Sand Environments
Authors: Pahmiyer R. C. , Fitzpatrick H.J. , Dugan J. 
Published: December 2007

Abstract
This paper describes, discusses, and compares the relative value of different completion-efficiency or completion-quality measurements that the industry currently uses to grade the technical success ofhigh-permeability sand-control completions. Some of the measures discussed are flow rate, total drawdown, productivity index, skin factor, and a permeability-adjusted skin factor. The paper presents the advantages and disadvantages of each measurement, along with a discussion of the variables that affect the measurement.
Although most people in the industry can agree on the variables, procedures, and methods that affect completion efficiency, how to best measure the completion efficiency is often debated. This paper presents an effective method to determine completion efficiency, a detailed method of estimating the completion efficiency measure, and the targets and values being achieved within the industry.
The methodology discussed includes corrections for turbulence effects, partial completion effects, and friction losses between the measuring point and perforations. Guidelines and procedures for collecting the required data are also presented.
The Development and Application of a Method for the Evaluation of Sand Screens
Authors: Ballard Tracey , Kageson-Loe Nils , Mathisen Anne Mette 
Published: December 2007

Abstract
This paper describes the development and application of a laboratory procedure for the evaluation of screens for sand control. The driving force for this study was to provide an independent evaluation of all screens on the market, in particular, the new generation of premium screens. The test addresses both aspects of screen performance, namely sand retention efficiency and plugging potential. The difficulties in setting up such a test are discussed, with particular attention paid to the elimination of experimental artefacts. Some of the pitfalls that may be encountered in laboratory evaluation of screens are highlighted.
The developed method has been used in screen selection tests for a particular field, and these results are also presented. The data illustrate the sensitivity of the technique for evaluating a range of screens on the same sand, and reasons for the differences in screen performance are explored. Furthermore, it was observed that the method of particle size analysis will affect the apparent particle size distribution of a sand. As a result such parameters as the uniformity coefficient may be completely different for the same sand depending on the method of size measurement.
Rigless WSO Treatments in Gas Fields. Bullheading Gels and Polymers in Shaly Sands: Italian Case Histories
Authors: Burrafato G. , Pitoni E. , Vietina G. , Mauri L. , Chiappa L. 
Published: December 2007

Abstract
Gels are used worldwide to control water co-production in gas and oil wells (WSO treatments) but the criticality of a correct placement in the Italian scenario had strongly limited their use in this Country. For instance, in gravel packed wells or in wells where the "ID casing/ID tubing" ratio is over 2.5, inflatable packers cannot be efficiently used for gel diversion; moreover, dual injection has to be usually applied with these tools, making a treatment very often too expensive and, as a result, unacceptable.
A review of water problems and displacement data collected during past matrix treatments performed in Italian gas fields led to the study of possible alternatives for treatments to be performed using standard crosslinked polymer and unusual displacement techniques. Relative Permeability Modifier (RPM) polymers were also considered and lab tested for WSO in shaly sands because the use of gels is still considered too risky. In fact, most of the treatments performed in Italy have to be performed bullheading in order to reduce the cost of the operations, making WSO treatments more attractive.
In this paper a brief summary of laboratory activities for a correct selection of polymers and gels, suitable for shaly, low permeability sands are reported as well as field treatments data and results.
Bullheading technique seems to be the only cost-effective and field proven placement method for rigless WSO treatments to produce marginal gas reserves from shaly, depleted, low temperature, multilayered reservoirs.
Testing of Down Hole Oil/Water Separation system in Lacq Superieur Field, France
Authors: Chapuis C. , Lacourie Y. , Lançois D. 
Published: December 2007

Abstract
As water production in mature oil fields continues to increase, we as an industry are continually challenged with how to handle the ever-increasing volumes of produced water. Downhole separation is attractive but needs further investigation about oil in water content after separation and its effect on formation damage of injection zone This paper is a description of field testing of Down hole Oil/Water Separation technology in well LA 90, Lacq Superieur field, SW France where oil and water streams are separately produced to surface in order to control fluids quality
The deviated well produces an heavy oil with high water cut from a carbonate reservoir. The new well completion consists of a hydrocyclone for oil/water separation and of electric submersible pump. The system can handle a flow rate from 150 to 270 m3/d with a water cut of about 97%. All parameters including the two well head string pressures, flow rate and pump speed were investigated during the flowing periods. Water cut, oil in water and droplet size were measured
Issues revolving around the quality of produced fluids are reviewed and preliminary results from the field trial are presented, specially the remaining oil in the water stream The improved knowledge of emulsion characterization leads to a better use of downhole separation system and a more accurate prediction of formation damage in the injection zone
Numerical Simulations of Hydraulic Fracture Link-up of Perforations at Deviated Wellbores
Authors: van de Ketterij R. G. , de Pater C. J. 
Published: December 2007

Abstract
A fracture starting from one perforation might fail to link-up with adjacent perforations and the fracture may break up into multiple fractures. Failure to link-up neighbouring perforations and the occurrence of multiple fractures reduce the communication between a propped fracture and the well.
Many experiments have been performed to study the near wellbore fracture geometry. They give a good insight in the impact of the treatment parameters on the near wellbore fracture geometry. However, they urge the need for a detailed numerical study of the first stages of fracture propagation as the processes that cause the near wellbore fracture geometry are not well understood.
The stress distribution on the wall of the perforations plays a decisive role as to where fractures initiate. In this paper we discuss the stress distribution around perforations around an arbitrary oriented borehole. We will present the results of an analytical model and a numerical model. Although the calculations give a fairly good description of the stresses near the wall of the perforations they do not always reproduce the site from which the major fractures initiate and give no explanation for the existence of multiple fractures.
This paper discusses numerical fracture propagation simulations from a perforated deviated borehole. We discuss fracture propagation as function of in-situ stresses, pressure, and perforation orientation. We will also discuss the link-up of starter fractures from adjacent perforations. The simulations provide a way to get a better insight in the processes that lead to the near wellbore fracture geometry. With this insight the fracturing treatments can be optimised and the formation of multiple fractures can be limited.
Impact of Formation Damage on Sand Production in Deep Eocene Reservoirs, Lake Maracaibo, Venezuela: A Case History
Authors: Tovar J. J. , Zerpa L. , Guerra E. 
Published: December 2007

Abstract
In the deep and layered Eocene reservoirs of southern Lake Maracaibo, Western Venezuela, some of the most productive fields such as Ceuta were discovered in 1978. Sanding problems are common in VLG 3676, Block VII, one of the most important reservoirs in the area where hydrocarbon production is from various intercalated thin. A major initiative was started in 1996 to evaluate the geomechanical, reservoir, drilling and production profile of the field in order to identify the problems and the options available to maximise production and final recovery. Intensive laboratory and field testing programs were carried out to develop the geomechanical model required and identify potential formation failure mechanisms. A review of drilling and completion practices indicated that formation damage contributed significantly to the sanding problem, while collapsed casing and, severe equipment erosion made, loss of production and well integrity common in the area. The evaluation of reservoir and production data from five (5) wells in order to quantify formation damage revealed skin values &gt; 80. The well model that was developed indicated that optimising drilling and completion practices could minimise and in some cases eliminate the sanding problem. A number of recommended changes to existing practices are now being implemented.
Reversible Invert Emulsion Drilling Fluids: Controlling Wettability and Minimizing Formation Damage
Authors: Patel Arvind D. , Growcock Frederick B. 
Published: December 2007

Abstract
Novel emulsifiers in reversible invert emulsion drilling fluids offer a unique opportunity for operators to control the wettability properties of the mud. Reversibility of the invert emulsion will provide economic advantages in drilling and completion and increased productivity. Optimal drilling performance and formation damage control are usually achievable by oil wetting the drill solids, formation and drillstring. On the other hand, optimal completion of a well - filtercake removal and cement bonding -- and disposal of drilled cuttings are best achieved by maintaining all surfaces water-wet. Filtercake removal is especially critical in the completion of horizontal openhole wells.
The reversible invert emulsion drilling fluids can be readily and reversibly converted from a water-in-oil emulsion to an oil-in-water emulsion and back to a water-in-oil emulsion using an acid-base chemical switch. This drilling fluid system is simple and easy to run without any drastic changes in current invert-emulsion technology. A novel surfactant package forms an invert emulsion in the presence of lime and a direct emulsion in the presence of acid. Reversible emulsion technology uses new emulsifiers that allow the drilling fluid to cycle between oil-wetting and water-wetting as frequently as one desires. Protonation and deprotonation of the surfactant is used to control the emulsion phase without drastic and uncontrollable viscosity swings.
The reversible invert emulsion drilling fluid has been successfully run in a North Sea well. The paper presents field data illustrating the economic benefits of this system and discussion on how the ability to change wettability can influence drilling and completion performance.
Role of Polymers on Formation Damage
Authors: Audibert Annie , Argillier Jean-François , Ladva Hemant K. J. , Way Paul W. , Hove Arvid O. 
Published: December 2007

Abstract
The filter cake is critical in preventing reservoir invasion by mud filtrate. This is of particular importance in open hole completions where damage cannot easily be bypassed. However little is known about the selectivity of the filtercake in controlling which components will invade the reservoir. An EC funded consortium between Statoil, Schlumberger Cambridge Research, and Institut Frangais du Petrole has focussed on the fundamental mechanisms of formation damage in order to design wellbore fluids for minimizing fluid losses and optimizing reservoir productivity.
Polymer invasion of the reservoir has been shown to have a great impact on permeability reduction. Possible damage with a typical polymer based drilling fluid was evaluated in terms of static and dynamic filtration, determining cake permeability, filtrate composition, and oil permeability reduction after mud exposure. The effects of polymers on filtercake properties and filtrate composition were found to be related to their incorporation into the filtercake and more specifically to their interactions with solids and solutes present in the fluid. Filtration conditions were also found to have significant effects. Measurement of polymer adsorption and retention in cores as a function of polymer structure, and formation saturation were also made to characterise the effects of mud filtrate on producing formations. This was correlated to the observation of rock invasion and damage using computed tomography (CT) imaging.
The improved understanding of formation damage caused by polymers is used to discuss criteria for effective and non-damaging fluid loss polymer architectures.