bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Gelling System for Acid Fracturing
Authors: Woo G. T. , Lopez H. , Metcalf A. S. , Boles J. 
Published: December 2007

Abstract
Typically, the gelling agents used in crosslinked hydrochloric acid are available as polymer dispersions with a pre-blended inverting agent or gellant activator. An inverting agent increases the polymer dispersion's viscosity initially and will further increase the polymer dispersion's viscosity over the shelf life of the product. As a result, the polymer dispersion's pour point and stability are adversely affected, thereby reducing the polymer dispersion's shelf life. Additionally, the use of a nonylphenol ethoxylate, the inverting agent commonly pre-blended in polymer dispersions, has been banned in the North Sea due to environmental concerns.
A new gelling system for crosslinked acid fracturing treatment has been developed. The system includes a micro-emulsion polymer gelling agent and a highly specific surfactant that is used as an external activator. The micro-emulsion polymer possesses very unique and more desirable properties such as a lower pour point and viscosity profile, a greatly enhanced dispersability, and a microscopic emulsion polymer particle.
With a lower pour point and innate viscosity profile, the gelling agent is readily pumped directly from the shipping vessels to the blending unit even in cold weather. With such a greatly enhanced dispersability, the gelling agent is readily dispersed in the hydrochloric acid without the risk of forming unhydrated masses or "fish eyes". Additionally, the microscopic emulsion particle greatly prolongs the shelf life of the gelling agent by virtually eliminating polymer settling. With the use of the special external gellant activator, the emulsion polymer could achieve 70% or more hydration within one minute. The characteristics of the gelling agent and the use of the external activator enable the gelling system capable of "continuous mix" or "on the fly" gelling operations.
In addition, this external activator is biodegradable making it more conducive to environmental concerns.
This paper describes the chemistry of the new gelling system, its enhanced gelling capabilities, discusses the results of lab testing leading to its development, and finally, the results of extensive field-testing.
Novel Approach to Borehole Stability Modeling for ERD and Deepwater Drilling
Authors: Tare U. A. , Mody F. K. 
Published: December 2007

Abstract
Borehole (in)stability in shales is a continuing problem which results in substantial annual expenditure for the petroleum industry ($700 million according to some conservative estimates). The environmental and business challenges of today have necessitated the development of a more realistic yet a more efficient modeling approach.
In order to develop an adequate borehole stability model, an in-depth understanding of the physics and chemistry of the interaction between the drilling fluid and the formation is extremely important. The chemical potential borehole stability model presented in this work addresses key issues in modeling borehole (in)stability problems for high angled extended reach and deepwater applications.
In addition to mud pressure penetration and osmotic interaction, the model also incorporates the effects of thermal stresses as a result of the drilling fluid and formation temperature difference. Several factors like the estimation of the in-situ shale activity, mud activity and rock strength properties based upon more conveniently tested laboratory parameters like porosity, shale dispersion, etc., are also included in this model.
The above model is the basis of a computer program which utilizes contemporary programming techniques and outputs information in terms of the mud weight as a function of hole angle and optimum salinity (for invert oil/synthetic based muds). Three case studies are presented in this work which demonstrate the straight-forward application and accurate predictability of the chemical potential borehole (in)stability model; to extended reach and deepwater drilling conditions.
Remedial Proppant Consolidation Using Resin Technology
Authors: Cole S. W. , Amundson M. W. , Allen J. S. 
Published: December 2007

Abstract
The Hugoton and Panoma gas fields are located in the Southwest corner of Kansas and the panhandles of Oklahoma and Texas. Historically, proppant production following propped hydraulic fracturing has been a recurring problem in these fields. For some wells, proppant clean out operations can make them unfeasible to operate. In all cases, the remedial costs associated with sand production are detrimental to the economics of the well.
In December 1996, a resin consolidation treatment was pumped on a Hugoton gas well to stop repeated pump failures due to post fracture proppant production. Based on the success of this treatment, the procedure has been used on 21 additional Hugoton and Panoma gas wells for six oil and gas operating companies. Of the 22 wells treated with resin, sand production has been eliminated on 14 of the wells. This paper reviews the candidate selection, design and execution of the resin treatments. Three case histories and conclusions from the overall results are also presented.
The Efficiency of Horizontal and Vertical Well Patterns in Waterflooding: A Numerical Study
Authors: Algharaib M. , Ertekin T. 
Published: December 2007

Abstract
The primary oil recovery mechanisms when are exhausted, leave enormous quantities of oil unrecovered. The advancement of oil recovery is a cardinal obligation in oil industry. From waterflooding to various thermal recovery operations, the predominant objective of the improved oil recovery processes is to increase the rate of recovery and the ultimate production from reservoirs. Most of the improved recovery processes are directed to improve the mobility of oil in porous media. Obviously, the field implementation scheme of these processes is also an important factor in determining the success of the project. The use of horizontal wells in waterflooding operations promises a pronounced improvement in the rate of oil recovery under certain conditions. In a low mobility ratio flood, horizontal wells are able to bring in an increase of 0.25 pore volumes to the recovery during the early injection periods compared to vertical wells. In this study, a numerical simulator is acquired to delve into the effectiveness of horizontal and vertical injector/producer well combinations in waterflooding applications. The effects of various waterflooding fluid parameters together with some operational design parameters are investigated. The analysis of the simulation studies conducted suggests that the combination, in which one horizontal and one vertical well are utilized, in several situations performs similar to the combination, in which two horizontal wells are incorporated.
Analysis of Horizontal-Well Responses: Contemporary vs. Conventional
Authors: Ozkan Erdal 
Published: December 2007

Abstract
Most of the conventional horizontal-well transient response models were developed during the 1980s. These models visualized horizontal wells as vertical wells rotated 90 degrees. In the beginning of the 1990s, it was realized that horizontal wells deserve genuine models and concepts. Wellbore conductivity, nonuniform skin effect, selective completion, and multiple laterals are a few of the new concepts. Although well-established analysis procedures are yet to be developed, some contemporary horizontal well models are now available. The contemporary models, however, are generally sophisticated. The basic objective of this paper is to answer two important questions: 1) When should we use the contemporary models instead of the conventional, simplified models? 2) How much error do we make by using the conventional models? This objective is accomplished by considering examples and comparing the results of the contemporary and conventional approaches.
Some Practical Examples Of Difficult Well Test Problems
Authors: Charles Dawari D. 
Published: December 2007

Abstract
Five practical examples of difficult field well test cases are examined. The source of the difficulty ranges from purely non-uniqueness problems in parameter estimation to several grades of severity of anomalous wellbore pressure and temperature behaviors. The examples include both gas and gas-lifted oil wells and demonstrate that regardless of the source(s) of the difficulty, they inevitably lead to a wrong or an extraneous solution. The examples show that non-uniqueness prone data lack clearly defined infinite acting radial flow segment on the log-log derivative profile, and that anomalous pressure responses inherently exhibits equally puzzling temperature profiles.
Optimizing Pumping Well Efficiency With Smart Fluid-Level Controller Technology
Authors: Giangiacomo Leo A. , Hill David R. 
Published: December 2007

Abstract
Oftentimes the management decisions that are required for pumping wells can be significantly improved by having an additional piece of information. If the fluid level in a producing well can be known in real time, many other pieces of information can then be calculated and/or inferred. With this additional information, better decisions can be made to improve the efficiency of the producing operation.
Fluid level machines, dynamometers, power analyzers, and pump-off controllers have all been very successful in increasing the operation of the rod-pumped well, and to a lesser degree, the progressive cavity and electric submersible wells. A recently patented fluid level controller technology enables the electrically pumped well to be optimized with real time fluid level data.
The fluid level controller can be used to measure and control the fluid level in a producing well without a packer to within a foot. It can penetrate foamy columns to read previously unavailable fluid levels below the foam. The level at which the pump turns on and off can be preset, and even automatically optimized. The producing bottom hole pressure can be calculated and used to improve the production and operating economics of many different types of artificial lift systems. It can also be used as a reservoir management tool. Its potential applications include:
preventing gas-locking, optimizing oil production from rate sensitive producers, conducting pressure transient tests, and evaluating the effects of injection well changes real time in an array of surrounding producing wells.
Field data has already revealed some interesting phenomena associated with downhole production observations that may lead to a better understanding of near-wellbore production mechanics. Changes in fluid level as gas rises through the annular column have been detected. Slug flow can be observed in what was thought to be steady state producers.
Problems Affecting the Design of Drilling Risers
Authors: Jones Marvin R. 
Published: December 2007

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

Abstract
With increasing water depth many of the factors considered in making decisions related to the overall arrangement and operation of floating drilling equipment change significantly in magnitude and, consequently, in relative importance.
The paper considers ways of evaluating such factors with sufficient accuracy to enable one to make those decisions which must precede the actual design work. The evaluations also serve to define problem areas which will require attention in the design process.
It concludes that increased cost effectiveness is extremely desirable and designs with increased cost effectiveness require a greater amount of cooperation between equipment users and makers than has existed to date.

Introduction
Drilling risers guide tools into undersea wells and conduct the returning mud flow from the blowout preventer stack to the drilling preventer stack to the drilling vessel. They carry choke, kill, and control lines and provide the usual means for supporting the blowout preventer stack during installation preventer stack during installation and removal.
In performing these functions they resist static and dynamic loads which are hard to predict accurately. In turn, they impose loads on both drilling vessels and wells. The magnitude of such loads may actually determine the overall arrangements and procedures of drilling operations. All of the loads mentioned increase as water depth increases and we shall consider depths from one to six thousand feet.
Before one can effectively undertake the design of a riser, he must have a procedure for deciding exactly what arrangements and procedures will be most effective. procedures will be most effective. Having decided, one can assume load conditions and design components accordingly.
The Piper Field - Development Plan For Rapid Field Evaluation
Authors: Pinson A. E. , Daniel E.L. 
Published: December 2007

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

Abstract
The discovery and six appraisal wells drilled in the Piper field provided data for the formulation of a flexible development plan which will permit rapid field evaluation. plan which will permit rapid field evaluation. The development plan will be modified as additional data are obtained so that the optimum development and operational plans can be used to obtain the maximum economic recovery from the field.

Introduction
The Piper field was discovered in December, 1972, and presented a classic example of the offshore oil industry's need to 1) make the decision to commit large sums of money toward development of a discovery at a very early stage of appraisal and 2) formulate development and operating plans rapidly in a situation of uncertainty regarding important natural features of the reservoir and its connected aquifer.
Preliminary studies on hypothetical fields of Piper size and water depth completed prior to the commencement of drilling permitted the Occidental group to begin an aggressive materials procurement and design programme immediately procurement and design programme immediately after the discovery well was drilled. Geological and engineering data obtained during the appraisal drilling provided information for rapid screening of possible oil displacement programmes and the selection of the general programmes and the selection of the general injection and producing well arrangement; a mathematical reservoir simulator was then used to devise a flexible development plan which will permit adjustments in well location and type (injection or production) as dictated by information gained early in the development/ producing phase. In particular, the development producing phase. In particular, the development plan should permit early determination of plan should permit early determination of the degree to which the field faults will act as impediments to fluid flow, and the strength of the natural water influx.
The development programme based on these studies includes a drilling/production platform which will accommodate a total of platform which will accommodate a total of 36 wells with plans for at least 24 producing wells and up to 10 water and 2 gas injection wells. Platform production and support facilities were designed for 250,000 B/D of oil production, 330,000 B/D of water injection, and 70 million SCF/D of gas injection. The platform will have two drilling rigs and will platform will have two drilling rigs and will incorporate safety features which will permit simultaneous drilling and production.
Drilling Through Deepwater Shallow Water Flow Zones at Ursa
Authors: Eaton L. F. 
Published: December 2007

Abstract
Wells drilled in the deepwater Gulf of Mexico often experience problems with shallow abnormal pressured sands. Successfully drilling through these sands has been an industry wide problem. Shallow water flow problems have caused the industry to junk wells prior to evaluation of any or all well objectives and prevented using discovery and appraisal wells as producers. Shallow water flow problems also caused the loss of the wells at the first Ursa Tension Leg Platform (TLP) site.
The Ursa field is located in the deepwater, 3800' water depth, Mississippi Canyon area of the Gulf of Mexico where shallow water flow problems have been severe. The sediments at Ursa contain massive, wet sands that are pressured above a normal seawater gradient at a very shallow depth below mudline. Different techniques have been used while drilling the discovery, appraisal, and development wells to attempt to successfully prevent and control shallow water flow problems. The severe shallow water flow problems at Ursa have been successfully overcome and the shallow batch set drilling program was completed at the second TLP site in mid-1998. Eleven wells, which required five casing strings, have been successfully drilled to below the base of the shallow water flow zones. This paper will discuss the problems encountered during exploratory, appraisal and development drilling at the Ursa field.
The New Concept Of Flexible Pipes. Their Manufacture. Their Applications In The Offshore Oil Industry. Field Experiences.
Authors: Behar Isaac , Levier Jean-Francois 
Published: December 2007

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

Abstract
The scope of the intended paper is to show to drilling and production engineering specialists the various offshore oilfield applications of the new COFLEXIP flexible pipes. Latest field experiences: oil and gas flowlines between platform and subsea wells, jetting hoses for burying pipelines, kill and choke lines connections, pipelines, kill and choke lines connections, subsea power transmission and control by armored composite umbilical cables, will be described.
The description of the structural design and of the manufacturing process will be illustrated to enhance the specific qualities of those flexible pipes (diameters from 1" to 12" - working pipes (diameters from 1" to 12" - working pressures from 500 to 15,000 psi). pressures from 500 to 15,000 psi)

Introduction
Fifteen years of research and development, three years of industrial production, this is the background of production, this is the background of COFLEXIP flexible pipes.
The versatibility of their structural design allowing to adapt their performances to the required levels, added to the Company's marketing policy of cooperating with its clients for a system approach of the problems, have allowed to solve or improve a certain number of them in offshore oilfield activities.
We will review some of those achievements after a short description of the design of the flexible pipe and their manufacturing.

STRUCTURAL DESIGN OF THE COFLEXIP FLEXIBLE PIPES PIPES
Roughly it can be described as an articulated steel pipe plus armor and plastic layers. The last ones insuring plastic layers. The last ones insuring their tightness. Figure 1 shows an example of one of the basic structures designed by COFLEXIP.
We find from the inside to the outside:A Rilsan (polyamide 11 polymer) lining, special plastic that is inert to crude oil and most chemicals.
Casing Running Milestones for Extended-Reach Wells
Authors: Mason C. J. , Allen F. M. , Ramirez A. A. , Wolfson L. , Tapper R. 
Published: December 2007

Abstract
In the pursuit to access reserves at ever increasing departures the ability to successfully run very long casing strings in extended-reach wells is essential. Even though casing running has been fairly extensively studied, it is evident in high departure wells, that both theoretical understanding and modelling are beginning to lag behind operational experience.
In this paper we examine a number of case studies from British Petroleum's world-wide drilling operations and have focused on wells where long 9-5/8" casing strings have been run. Here, we define the length of 6,000m (20,000ft) as the casing running milestone.
We demonstrate the application of time-based data and advanced analysis techniques to illustrate a number of results that are fundamental to future progress. Examples include the effects of OBM and WBM systems, centralisation strategies and drag reduction techniques. In particular, we present the latest learning from full and partial casing flotation - which is now in routine use at the Wytch Farm oil field in Southern England.
The results in the paper also demonstrate an improved understanding of the effects of casing stiffness, wellbore tortuousity and mud rheology, in addition to the usual frictional drag mechanism.
In order to satisfy future requirements, it is desirable to develop metrics that can usefully quantify benefits whenever new techniques, technologies or strategies are used. To this end, we detail the shortfall in current drag modelling techniques and prescribe where improvements are required to fulfill immediate needs and shape future demands.
An Approach to the Evaluation of Oilfield Development Alternatives Using Reservoir Simulation Models
Authors: Archer John S. , Keith David R. , Letkeman John P. 
Published: December 2007

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

Abstract
The paper provides an approach to the use of reservoir simulation in North Sea oilfield development. The use of simulators prior to field production is a departure from traditional application and the authors have sought to illustrate that reservoir simulation models can be a relevant part of an overall field development strategy. The models are used to evaluate alternative production schemes and can be upgraded into operating tools as more field information becomes available.

Introduction
In this paper we will review the application of reservoir simulation models in assessing reservoir development alternatives for North Sea oilfields.
In recent years the vast exploration budgets allocated to the search for North Sea petroleum resources have resulted in the petroleum resources have resulted in the successful discovery of new offshore oil and gas fields. Many of these fields lie in water depths between 300 and 700 feet and are located in parts of the North Sea notorious for harsh weather. The focus of activity is now changing to some extent from exploration to development of these resources. Such development requires large capital expenditure and early return on investment. It is necessary to order development platforms and production equipment soon after initial field discovery, when only a limited amount of data is available from exploration wells. The huge investments required for field development justify the need for management to base plans on the fullest technical appraisals that are possible within the narrow time frame; appraisals that recognize the limitations of the available data and effects of different interpretations of the data.
To this end, reservoir simulation models are being used to optimize development soon after the field is discovered. Sophisticated computer methods are used for solving the mathematical equations that describe fluid flow in a grid system that represents the physical parameters of the reservoir. The equations are generally non-linear and require numerical solution with the aid of high speed computers.