bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Uses Of Pressure Build-Up Analysis In The Anadarko Basin Completion And Repair Operations
Authors: Smith Kim L. , Feemster W.E. 
Published: December 2007

Abstract
The Horner and Miller-Dyes-Hutchinson methods of pressure buildup analysis have long been the basis of such analysis. Advances in analysis theory have added to and combined these two methods to provide engineers with a thorough understanding of a reservoir. This article compiles a practical method of pressure buildup analysis for the Morrow formation in the Anadarko Basin of Central Oklahoma based on experience gained from repeated analysis of pressure data in this region. The article reviews the familiar equations for permeability and skin effect, and discusses the three plots required for proper analysis with a detailed look at afterflow, fracturing, identification of the correct straight lines on each plot, and average reservoir pressure. Buildup analyses for both pre-frac and post-frac pressure data are presented for a gas well and an oil well. The analysis pressure data are presented for a gas well and an oil well. The analysis is discussed with emphasis placed on the value of such testing in completion and workover operations.

THEORY
All pressure analysis is based on the two-dimensional diffusivity equation in cylindrical coordinates written:
(1)
The diffusivity equation is assumed to describe the flow within the reservoir and the equation itself assumes constant porosity, fluid viscosity, compressibility coefficients, and formation dimensions, as well as single-phase, isothermal, radial flow toward the wellbore, a slightly compressible flowing fluid, isotropic permeability, and no gravity effects.
Horner presented a solution of this equation which resulted in the basic practical equation used in all pressure analysis. practical equation used in all pressure analysis.
Water-Base Spacer Increases Success Ratio Of Cement Jobs In Illinois Basin
Authors: Griffin T.J. , Crowe W.L. 
Published: December 2007

Abstract
The application of a water-base spacer ahead of cement during oil or gas well cementing operations improves cementing results. Better bond logs are achieved, better zone isolation is accomplished and stimulation treatments are more effectively applied. With more effective stimulation treatments, production results are improved. Bond logs production results are improved. Bond logs and field results including production data are presented.

Introduction
Wells in the Illinois Basin drilled through the St. Genevieve limestone and all formations through the Trenton formation have had production which was far below the expectations of formation log and drill-stem tests. These fractured limestone formations occur between 2000 and 4000 feet and are drilled with a simple, light-weight, waterbase drilling mud. The poor production is attributed to a lack of zone isolation by the cementing treatment. Poor zone isolation occurs when mud is left in the annulus and forms a channel behind the cement.

ELEMENTS OF GOOD CEMENT JOB
To ensure a good cement job, the best cementing techniques must be employed. Of course the first element of a good cement job is the cement itself. The cement system must be properly designed for the well conditions If well conditions permit, casing hardware such as centralizers and scratchers should be employed, especially across any zones of interest or future zones of interest. After the casing or liner, has been run into the hole, mud should be circulated at least "bottoms up", or until it is in good shape. Following mud conditioning, cement must be mixed and placed using proper techniques. For cement to make intimate contact with the formation and pipe, which is necessary to achieve good bonding and good zone isolation, all the mud must be displaced by the cement. Pipe movement, such as rotation or reciprocation Pipe movement, such as rotation or reciprocation during placement of cement will greatly aid mud removal. Spacers are also available which will improve mud removal and its replacement by cement.

REMOVAL OF MUD
Removal of mud may be a very difficult task, even with proper mud conditioning, pipe movement, and use of casing hardware. Most muds are incompatible with cement, whether they are high density muds or simple, lightweight muds.
A Search For Energy From The Antrim
Authors: Matthews R. David , Humphrey John P. 
Published: December 2007

Abstract
The Dow Chemical Company's interest in oil shale was directed in the 1950's toward in situ processes and local shales, specifically the Antrim, a black Devonian shale which occasionally produces natural gas and which yields produces natural gas and which yields 9–10 gallons of oil per ton when retorted. It underlies most of the lower peninsula of Michigan.
Various field studies by Dow of the Antrim shale have resulted in the drilling of some 21 wells and the cutting of over 5000 feet of core. Dow researchers have retorted Antrim shale in laboratories and in surface retorts and underground combustion experiments have been conducted in a quarry and through bore holes at depths of 1200' and 2600' below the surface. Both high pressure air and oxygen have been used underground as reactants. Hydraulic fracturing and chemical explosives have been used on a massive scale in attempts to generate the necessary fracture permeability for in situ retorting. The costs have been large and the technological problems yet to be solved are formidable, however the potential of the eastern oil shale is so large that a continuing effort has been recommended to the Federal Government.

Introduction
As early as June, 1955, research planners for The Dow Chemical Company were suggesting that underground processes, including in situ retorting, be studied with specific attention to the essential problem of rubblizing the strata, because the long range availability of energy and organic raw materials was not favorable at some Dow plant sites. A block of Colorado oil plant sites. A block of Colorado oil shale was purchased, however, interest soon shifted to a local oil shale a little more than half a mile below our power plants at Midland, Michigan. This shale, plants at Midland, Michigan. This shale, the Antrim of Michigan, is a Chattanooga-type shale that represents only a small part of the very extensive oil shale deposits of Devonian age in the Eastern and Mid-eastern parts of the United States (Figure 1). parts of the United States (Figure 1). The U.S. Geological Survey estimates that these shales underlie an area of over 400,000 square miles.
Ecotoxicology of Oilfield Chemicals: The Relevance of Evaluating Low-dose and Long-term Impact on Fish and Invertebrates in Marine Recipients
Authors: Beyer Jonny , Skadsheim Arnfinn , Kelland Malcolm A. , Alfsnes Kjetil , Sanni Steinar 
Published: December 2007

Abstract
Should future regulation of the use and release of E&P chemicals offshore focus more on tests of chronic effects at low levels of contamination, in line with recent ecotoxicological discoveries? Within this context, what groups of E&P chemicals are relevant, and what kind of effects and test methods should be incorporated in revised regulations? Can this altered but more relevant environmental focus potentially be beneficial for both the environment and the oil E&P sector? This presentation will discuss and answer these issues.
Simulation of a Tight Gas Reservoir with Horizontal Multifractured Wells
Authors: Ehrl E. , Schueler S. K. 
Published: December 2007

Abstract
The concept of multiple fractured horizontal wells has been successfully used for the development of a deep, ultra-tight Rotliegendes gas reservoir. Because of extremely low permeabilities (0.01 – 0.02 md) conventionally fractured vertical wells produced at uneconomically low gas rates. The pilot well Soehlingen Z10 combined the methods of horizontal drilling and multiple fracturing and proved an economic technique for developing the significant gas resources in the tight gas reservoir.
An integrated 3-D geologic model and a field-scale reservoir simulation model were used to optimize future field development. The wells were modelled with a system of local grid refinements (LGR) around the horizontal wells. Adjusting permeabilities and cell sizes of the hydraulic fractures and the surrounding reservoir area helped solve the numerical stability problems without affecting simulation of long-term production performance. The history match for the existing multiple fractured horizontal well, Soehlingen Z10, was based on a five-year production period. Previous analytical studies were confirmed by numerical results. A multi-well program was developed with up to eight wells of 1,000 to 1,500 m long horizontal sections. Each well will be stimulated by 5 to 7 hydraulic fractures depending on the horizontal section length. Timing and sequence of the planned tight gas wells were analyzed using an integrated subsurface-surface study. The development plan incorporates the spare capacity of existing surface facilities and the actual production decline of other producing horizons in the field. Following this study, the Soehlingen Z13 well was drilled, stimulated and brought on production in 1999.
Application of Azimuthal Density while Drilling Images for Dips, Facies and Reservoir Characterization – Niger/Delta Experience
Authors: Akinsanmi O. B. , Aibangbe O. , Kienitz C. 
Published: December 2007

Abstract
The azimuthal density while drilling tool has been successfully utilized in high angle well drilling and evaluation. The evolution of the imaging technology from this tool has opened new avenues in horizontal well evaluation, and the resultant imaging answer product has successfully been used for detailed structural and sedimentological analysis for characterizing reservoirs beyond the resolution of surface seismic.
Conventional well to well correlation techniques have often proven inconclusive in placing laterals in the optimum position within the reservoir. Resulting production from the lateral drain holes has been seen to be greatly influenced by the positioning of the well bore relative to structural and formation dip. Formation dip and structural features have historically been acquired from wire-line logging tools. However, high angle wells present operational difficulties which often result in a decreased use of wireline. Images acquired while drilling by the azimuthal density tool provide a method of resolving the correlation uncertainties, and allow quantification of the structural and sedimentological interpretation and the subsequent production contribution of each zone in the lateral.
The fields where this application was utilized are analyzed. From the data analysis an extra opportunity in terms of reserves has been identified.
Gas shut off using foam: The Solution for unwanted Gas Production?
Authors: Ligthelm D. J. , Eijden G. J. M. van , Gronsveld J. 
Published: December 2007

Abstract
Gas shut off technology for wells with a high gas/oil ratio is extremely valuable to improve oil production and reduce environmental pollution. Foam treatments have been applied to reduce unwanted gas inflow. However, results have not always been favorable. This paper presents a field case supported by a modeling study of successful foam shut-off treatments carried out in the South Chinese Sea. This study shows that the possibility of success of gas-shut-off treatments can be greatly enhanced by having a good understanding of the process parameters. In the Champion field, Brunei, an increasing number of oil wells are shut in due to high gas/oil ratio. In November 1998, three wells were treated with a surfactant/polymer (foam) solution in water, co-injected with nitrogen. In two wells the gas/oil ratio was substantially reduced but also a significant loss in oil productivity was observed, which partly restored in the course of time. The treatments were based on laboratory core flow experiments under reservoir conditions. The experiments served to design the field trials and as input data for simulations with a numerical radial well model, which was used to interpret the field trials. The reduction in gas mobility by a factor between 2 and 10 as observed in the field is consistent with the results of the laboratory experiments.
The study identifies the permeability and temperature window and the type of geological setting and well configuration for which the applied foam system will be successful. This is essential to screen potential candidate wells. It will be shown that in future treatments less damage to the oil productivity and lower costs are possible by omitting nitrogen gas and by reducing the injected volumes.
VLE WAG Injection Laboratory Field in Maracaibo Lake
Authors: Manrique E. , Padrón R. , Surguchev L. , De Mena J. , McKenna K. 
Published: December 2007

Abstract
The VLE WAG pilot in Maracaibo Lake is one of the laboratory IOR fields of the State Venezuelan Oil Company PDVSA. The area of the VLE WAG pilot encompasses 5 production wells, one injection well and one observation well. The producing reservoir C-23 is stratified heterogeneous sandstone. The WAG injection pilot in the VLE field is planned to start in year 2000. The main objective of the WAG pilot is to improve oil recovery from the area being produced since 1991 under natural pressure depletion.
Available data were integrated to have representative description of the reservoir and fluids simulation model. The stochastic description of the C-23 reservoir was used to build the model of the pilot area. Available well data were used to condition the stochastic geological model. Core flood experiments were simulated and interpreted to establish relative permeability data. The available PVT data from different production time periods was reviewed and black oil fluid description was established to account for injection hydrocarbon gas dissolution and oil swelling effects under WAG injection. The established simulation model was used to history match production data and to evaluate WAG injection scenarios. The injection well has dual completion for separate simultaneous water and gas injection cycles. Cyclic simultaneous water and gas injection in the VLE WAG pilot has a potential to improve waterflooding recovery by 5-7% of STOOIP after 5 years of production. The planned tracer injection program will provide additional data for further simulation model adjustments and improvements.
This paper will discuss the integration of data to establish a representative simulation model, history matching and WAG process modelling, VLE WAG laboratory field evaluation.
Predicting the Reservoir Response to Intelligent Wells
Authors: Thompson I. M. , Sarkar R. , Parker E. D. 
Published: December 2007

Abstract
Recent developments in completion design have seen the evolution of the intelligent well. The ability of this well to both measure and control production, and/or injection, within the subsurface is considered a major step forward in field management. It is therefore crucial to be able to model and understand the impact on the field of the technology prior to installation. By modelling the entire system the ideal completion design and field location are evaluated, whilst the reservoir response to the variable choke is predicted for the life of the well. The economic value of the technology can now be understood.
Previous attempts at modelling intelligent wells have crudely adjusted either perforation skin, or near wellbore permeability, to mimic the choking effect. However, the challenge is to firstly, develop a model which correctly predicts the fluid and pressure distribution throughout the completion as well as across the reservoir for each choke orifice, and then to apply the model as a reservoir management tool.
This paper describes a method of executing the challenge by incorporating the surface network and variable choke model of a reservoir simulator within the subsurface. The model simulates the multiphase flow and pressure distribution within the annulus and tubing for any choke orifice. Production is allocated to each choked section and perforation accordingly. Simple adjustments, or the incorporation of new components, within the network, readily permits simulation of the field response to various completion designs.
Performance sensitivity of the model is evaluated in simple homogeneous and heterogeneous environments. Intelligent well models are then developed for two conceptual field developments. In each, field performance is compared with traditional completion designs.
An Integrated Risk Model for Reservoir and Operational Costs with Applications to Total Value Chain Optimization
Authors: Huseby Arne Bang , Brækken Egil 
Published: December 2007

Abstract
The paper presents a new methodology for building integrated risk models for reservoir and operational costs. Although the resulting models are fairly simple, they have proved to be adequate in several real-life applications in large field development projects as a part of a total value chain risk analysis. By using these models it becomes possible to optimize intervention strategies with respect to the total net present value of the project or other success criteria such as break-even price.
When analyzing operational costs related to an oil or gas field, one usually develops a static cost profile based on the assumed expected yearly production throughout the lifetime of the field. However, when reservoir uncertainty is introduced, this approach breaks down, as different production scenarios must be matched with corresponding operational cost profiles. A typical risk analysis involves carrying out some sort of Monte Carlo simulation. To be able to do this, it is necessary to establish a more dynamic link between reservoir and operational costs. While some of these costs are more or less constant independent of the production, others depend heavily on how much the reservoir produces. In this paper we focus on the last category. It is natural to divide such costs into two subcategories: rare events with high costs, e.g., well interventions such as side-track operations, and frequent events with low costs, typically scale squeeze operations. Two different models will be presented dealing with these issues. For the rare events with high costs case, we present a lifetime model where the time is measured in cumulative production. For the frequent events with low costs, the relation between production and operational costs is developed based on curve fitting.
Troll West - Reservoir Monitoring by 4D Seismic
Authors: Elde Rigmor M. , Haaland Annelin N. , Ro* Hans Egil , Ystad Bjørnar , Zachariassen Eli 
Published: December 2007

Abstract
A seismic monitoring pilot survey was acquired in September 1998 for the purpose of qualifying time lapse seismic technology on the Troll West oil field. The main objectives for seismic monitoring on Troll West are to detect areas containing undrained oil and to reduce the uncertainties related with simulated contact movements. The seismic monitoring study has established effective methods for both seismic processing sequences, 4D analysis and history matching, and it has been shown that the seismic monitoring technology is useful on the Troll West oil field.
Avoidance of Formation Damage by Application of Proper Drill-In Fluid (A Case Study of a Mature Field)
Authors: Gaurina-Medjimurec N. , Steiner I. , Simon K. , Matanovic D. 
Published: December 2007

Abstract
Horizontal well – 1H was drilled in a mature field in Croatia with an extended open hole interval and a high differential pressure. As a result, differential sticking has occurred when drilling the horizontal section.
This was the first well to be drilled in that area with application of a drill-in fluid that included specially sized calcium carbonate bridging agent with a blend of viscosifying and filtration control polymers.
To identify the best drill-in fluid composition for the horizontal section, three compositions were evaluated based on fluid-loss control and plugging properties, low-shear rheology (LSRV) and formation damage potential.
Innovative Development Engineering Techinques
Authors: Gayton P W , Miller S D , Napalowski R 
Published: December 2007

Abstract

Triton Development
Increasingly, field developments are characterised by fragmented marginal reserves where development risk cannot be amortised through extended appraisals without compromising project value. It is now important to tailor the system design and phase the capital expenditure to fit with production uncertainties and manage downside risk.
With reference to the Triton development, this paper presents techniques and methods that enable marginal fields to be developed with facility, drilling and reservoir risk fully understood.
The Triton development involves two separately operated fields and three operators – Guillemot West/NW (Veba), Bittern (Shell Expro) - combining in the new build Triton FPSO (Amerada Hess). Rigorous through life production network deliverability reflecting reservoir performance was required to enable identification of central facilities concepts. Co-ordination between the various players was crucial to the success of the project and this was facilitated by the use of integrated reservoir/production system models.
Three techniques are presented in detail:
Operating envelope mapping – using a full integrated production system model (Pipesim) and OLGA in combination to generate performance and behaviour maps to provide decision support to flow assurance design issues.
Pipesim FPT – Field planning tool. A life of field total production network plus reservoir model simulation tool coupled with field development event logic control that allows detailed inflow/outflow derivability, thermal performance and equipment performance to be tracked over field life.
Risk and value engineering – integrated reservoir, facility and economic system modelling coupled to Monte Carlo risk simulation to give life of field NPV and recovery estimates as well as providing risk based decision support.
The paper shows that all of the above techniques can be combined to provide a powerful systematic approach to development engineering.
Blacklick Project Summary, Indiana County, Pennsylvania
Authors: Bajek David T. 
Published: December 2007

Abstract
Coalbed methane has become a viable resource for meeting the needs of natural gas consumption. Many projects were started in 1991 to take advantage of tax credits offered by FERC. These projects have had to carry on beyond the tax credit. One such is Belden & Blake/Devon Resource’s Blacklick Project. The Blacklick Project was started by O’Brien Methane Production as an attempt to cash in on tax credits. O’Brien drilled twenty wells but only six were treated before the project was sold in late 1992 to Devon Resources Inc. and Belden & Blake Corporation partnership. The remaining initial wells were frac’d over the course of the next two years. The overall results were not stellar. Water production exceeded expectations, while gas production had not followed the "typical" incline experienced at other CBM Project areas. In late 1995, Belden & Blake shifted responsibility for the Project from the Corporate Office to the satellite office at Pleasantville. At this time a complete review of the Geology and Operations was under taken. The results of this review spurred a new round of drilling. This drilling utilized the geology to pick optimum areas. The short falls discovered in the operational review were also tested. The 1996 CBM program for Blacklick exceeded the expectations of all involved. The process used to improve this project area required cooperation of Engineers, Geologists and Field Personnel. It also utilized a fair share of practical experience of pumping operations learned in shallow oil production.