bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Progressing Cavity Pump: A Cost-Effective Multiphase Transfer Solution
Authors: Mirza Kamran Z. 
Published: December 2007

Abstract
Based on the progressing cavity pump principle, Robbins & Myers, Inc. has developed a surface transfer system for transporting all multiphase fluids produced from the well simultaneously through a single pipeline to a central processing station. It is capable of handling a wide range of flow regimes and gas fractions up to 99%. The system's approach provides optimum pump performance under continuously changing conditions at the wellhead.
The data presented in this paper was recorded at an actual field location in Alberta, Canada. A special multiphase progressing cavity pump system was installed at the satellite and resulted in reducing the wellhead pressure. At the same time, a significant increase in overall fluid production was recorded, including a substantial increase in the oil output.
This case study describes the problem and the solution, and explains the benefits of the progressing cavity multiphase pump system. A comparative analysis is presented for the production rates before and after the installation of the multiphase pumping system. An economic analysis is also presented to demonstrate the cost-effective advantages of the progressing cavity multi-phase pump system, which offers lower capital, installation and operating costs, and an attractive return on investment.

Introduction
Progressing cavity (PC) technology and its application in a multitude of industries has evolved for well over half a century. Likewise, the concept of multiphase fluid transfer is not new nor is it considered revolutionary. However, it is a process that has inspired the development of innovative, cost-effective alternatives to traditional, ineffective methods of fluid transfer. At the heart of the multiphase fluid transfer system is a redesigned, field-proven progressing cavity pump. This paper examines the technology behind the progressing cavity pump, its capabilities and applications as they apply to multiphase fluid transfer in lowering operating and repair costs, as well as extending well production and well production life. Actual field test results are shown to confirm the benefits of multiphase pumping and illustrate its potential for the oil and gas industry.
Running, Setting and Cementing Casing in Deep Wells
Authors: DeGeer Don W. 
Published: December 2007

This paper was prepared for the 1972 Deep Drilling Symposium of the Society of petroleum Engineers of AIME to be held in Amarillo, Tex., Sept. 11–12, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
A typical casing program for the latest wells drilled in the Washita Creek Field would be 20", 13 3/8" 9 5/8", 7" liner, and a tapered 7" × 4 1/2" production string.
An earlier casing program for the Washita Creek wells was 2411, 1611, 11 3/4", 9 5/8", 7" liner and a 7" tie-back production string. production string. For the latest program, included is a description of each casing job, the equipment used, and the method used to run and cement each string.
Some of the troubles which were encountered and the remedies that were effective are described.

Introduction
This paper is based on Phillips Petroleum Company's experience in the Petroleum Company's experience in the Gageby Creek and Washita Creek fields in the Texas Panhandle. As the Washita Creek wells were the latest drilled and the deepest, the data given will be from this field.
A typical well for the area was drilled and cased with the following program: program: Hole Casing Casing Size Depth Size (In.) (Ft.) (In.) Remarks
24 400 20 Conductor. Cement to surface to protectfresh water sands.
17 1/2 4,200 13 3/8 Surface. Set on or in top of Brown Dolomite. Case off unconsolidated formations prior to drilling loss circulation sections.
12 1/4 13,900 9 5/8 Intermediate. Set in top of Morrow Shale. Case off low pressure formations before drilling the high pressure Morrow.
Drilling a Record Mississippi Wildcat
Authors: Klementich E. F. 
Published: December 2007

Abstract
This paper discusses drilling the She Murphy USA 22-7, a 23,455-foot Jurassic wildcat located in Wayne County, Mississippi. This well is extraordinary from several standpoints:
- a new state depth record was reached;
- two very severe and nearly instantaneous kicks with a flowing capacity in excess of 70 BPM were successfully brought under control;
- 3,551 feet of 4 1/8" slim hole was drilled with ultrahigh mud weights, 19.2 to 20.3 ppg, in an underbalanced condition, and
- a flow test of a high pressure (8,300 psi shut-in) salt water zone was conducted.
This report presents a chronological history of the Shell-Murphy USA 22-7 and discusses the drilling techniques that were successfully used to bring the well to total depth. In addition, the author's thoughts will be presented on the source of the ultrahigh pressures and other phenomena peculiar to this pressures and other phenomena peculiar to this well.

Introduction
In late 1969 there were two areas in Mississippi where wells deeper than 20,000 feet were being drilled, in the central part of the state around the Jackson Dome and in southeast Mississippi in a piercement salt wall province (Fig. 1). In both areas the objectives were the Smackover and Norphlet formations (Jurassic age). To date one of the most difficult wells to drill was the Shell-Murphy USA 22-7, a Wayne County, Mississippi wildcat located in the salt wall area.
Deep, high pressure sour gas wells are in themselves unique but do not individually deserve special reports. General drilling and completion practices for such wells were outlined in a previous reported However, this well is extraordinary from several standpoints:
- a new state depth record, 23,455', was reached;
- two severe and nearly instantaneous kicks (3,700 and 2,400 psi shut-in drill pipe pressure) with a flowing capacity greater than 70 pressure) with a flowing capacity greater than 70 BPM were successfully brought under control;
- 3,551' of 4 1/8" hole was drilled with ultrahigh mud weights (19.2 to 20.3 ppg) in an under-balanced condition; and
- a flow test of a high pressure zone was conducted.
This paper presents a chronological history of the USA 22-7 and outlines the drilling techniques that were successfully used to bring the well to total depth. In addition, various thoughts are presented on the possible source of the ultrahigh pressures and other phenomena peculiar to this well. peculiar to this well.
Deliverability Enhancement and Well Testing of Two Gas Storage Fields in Mt. Simon Formation – Case History
Authors: Azari Mehdi , Guoynes John , Soliman Mohamed , Fugate Mike 
Published: December 2007

Abstract
A pilot study was conducted in two aquifer gas storage fields completed in Mt. Simon formation located in North Central Illinois to select candidate wells for deliverability improvements.
Eleven wells were selected to evaluate their responses to several different stimulation technique. High pressure perforation washing. Re-perforating with high density charges, extreme overbalance surging (EOBS)1-3, selective injection packer acidizing (SIP), and coiled tubing acid injection were all used to reduce the near-wellbore pressure losses
Each well was tested before and after every treatment to select treatment types and to compare the improvement techniques. The results and the responses of the wells to these treatments will be documented for further deliverability improvements in these two fields.
Significant improvements were achieved with EOBS and SIP acidizing techniques. The techniques and the procedures used to improve the deliverability in these two gas storage fields are presented in this paper. The procedure and the well test analyses used in the four wells detailed in this paper represent the three main treatment techniques of EOBS, SIP acidizing, and coiled tubing acidizing.
Heavy Oil Reservoir Management
Authors: Thakur Ganesh C. 
Published: December 2007

Abstract
Good prices and continued cost reduction are helping production from heavy oil reservoirs worldwide. Some estimates expect Alberta, Canada’s heavy oil sands production to exceed 1.2 million b/d in the near future. Recoverable bitumen reserves in Alberta are estimated at 300 billion bbl. In Venezuela, the government companies are forming partnerships to enhance recovery in the Orinoco tar sands. It could be producing 600,000 b/d by 2000, and it contains about 300 billion bbl of recoverable heavy oil and EOR reserves. In China, CNPC (China National Petroleum Corp.) produces about 150,000 b/d of heavy crude from some 7000 wells, and it has about 8 billion bbl of heavy oil reserves. Heavy oil resource base in the world may exceed 4 trillion barrels. Thus, it is of great importance to pay attention to heavy oil reservoir management.
World Record Dual- and Tri-lateral Wells
Authors: Azoba H. , Akinmoladun O. , Rothenhofer H. , Kent D. , Nawfal N. 
Published: December 2007

Abstract
The lateral reach of earlier symmetric fork-type dual-lateral wells were limited by torque and drag. Attic zones are also left between wells leading to a potential 7% reduction in ultimate recovery. After an in-house torque and drag modelling of several well profiles, the assymetric fork multilateral well profile was seen to be capable of eliminating the shortcomings.
Six of these assymmetric-fork multilateral wells have since been drilled: 2 of them to world record total horizontal lengths! The new design will facilitate some 25% reduction in field development costs, 17% reduction in torque and drag, as well as 42% reduction in environmental footprint.

Introduction
Production from the Shuaiba reservoir commenced in 1984 with vertical wells. The first successful horizontal producer, a sidetrack, was completed in 1991. Up to August 1997 some 40 horizontal wells including 11 multilaterals have been drilled.
Initial well rates from long horizontals were up to 750 m3/d. However, severe pressure depletion was observed in the areas of the high productivity horizontal producers.
Consequently, a line-drive waterflooding was started in 1995: produced water is injected through horizontal wells placed below the OWC to provide pressure support. The oil is produced through horizontal wells drilled along the top of the low relief structure. Earlier designs consist of single horizontal producers and dual lateral water injectors, drilled in symmetrical, 'tuning fork shape' with injector-producer lateral spacing of 125m (i.e., injector-injector spacing of 250m). After drilling 5 symmetrical fork dual lateral injectors, it was established that drags in the symmetrical-fork wells were constraining drilling progress and lateral reach. Other well profiles were then analysed for torque and drag and the asymmetric-fork profile selected. Six asymmetric-fork wells (3 dual- and 3 triple-laterals) have since been drilled, two of them to world record total horizontal lengths.

Geology
The overburden consists of Tertiary and Cretaceous deposits. Some 80 m of Nahr Umr shale are the top seal for the Early Aptian Shuaiba limestone reservoir.
The Shuaiba structure is a low-relief dome, truncated on its southern side by a WNW-ESE trending fault. With the exception of this boundary fault, no faults with a vertical throw of more than 3 m have so far been detected.
The dominant lithology in the Shuaiba formation is porous lime wackestone typically with 25% porosity and 2 mD permeability. The best permeability and porosity are found in a reasonably thick layer at the top.
Core data suggests that vertical permeability in the reservoir is good, with kv being nearly equal to kh. This has been confirmed from well performance modeling and RFT pressure data. The absence of barriers to the vertical movement of fluid is of particular importance for the recovery process. Barefoot completion: The Shuaiba structural homogeneity and the absence of water fingers dictate that the wells be completed barefoot.
Multi-Lateral Well Planning
Authors: Lowson Brent 
Published: December 2007

Abstract
Multi-lateral drilling and completion techniques involving cased primary and lateral well-bores have become increasingly prevalent in the oil and gas industry over the past five years. The experience gained in this time has permitted technological advances which now allow operators the flexibility to plan for increasingly complex multi-lateral applications.
An effective planning process is essential to the successful drilling and completion of every multi-lateral project, whether it be a single open hole lateral application with no re-entry or isolation requirements or a complex combination of multiple laterals in different formations requiring fully selective reentry and isolation capabilities.
This paper discusses the many technical issues which must be considered when planning the drilling and completion of multi-lateral wells.
Consideration is given to the selection of the optimum drilling and completion systems for particular applications, and includes a comparison of the advantages and disadvantages of pre-milled casing window systems with those of downhole window milling techniques.
Various drilling and completion issues are then discussed in detail as they relate to the planning of multi-lateral wells. These issues include well profile considerations; cementing options; re-entry and isolation requirements; well control considerations; constraints imposed by the technology and the importance of contingency planning. A case history which serves to illustrate the importance of a comprehensive planning process is presented.
The paper presents a set of guidelines which are based on a continually increasing level of experience gained during the installation of over 100 casing window systems in various applications worldwide in addition to the extensive bench testing which has been carried out on these systems. This experience has resulted in enhanced planning processes which lead to reduced risk when implementing multi-lateral systems.
Use of 1.6/1.7 Kg/I Slurry for Cementing Production Casings
Authors: Macculi Paolo 
Published: December 2007

Abstract
A major concern in drilling operations is the problem of carrying out cementing jobs for production casings where no fracture margin during the slurry displacement exists. In general in order to resolve this problem, a double stage cement job, the use of a liner with a subsequent tie-back or one more casing string is required.
In the Adriatic Offshore we have experimented with the use of light weight high mechanical resistance slurry (SG = 1.6 / 1.7 kg/1) in 7" production casing cement jobs in order to complete the operation in a single stage.
These cement jobs have been carried out, with positive results, in six of the fourteen Angela platform wells, in three of the four Antonella platform wells, in one Anemone cluster well (double stage cementing to avoid one more casing string), in the Antares 1 s.t. and the Agostino 11 s.t. wells.
The wells, where the 1.6 / 1.7 Kg/1 light weight slurry has been used, have an average total depth of 3600 m VD, their intermediate casing shoes are set at an average depth of 1800m VD.
The use of light weight slurry, composed of 10 / 30 % Microsilica by cement, has led to a reduction in the hydrostatic load, an optimisation of rheology and filtration control (maximum differential pressure of 400 atm exist at the end of displacement) while guaranteeing the necessary high mechanical resistance.
According to field data, we can conclude that the use of light weight slurry has the following advantages:a single stage cement job can be used instead of the more complex double stage one with the consequent improvement in well and rig safety; in particular cases, a light weight slurry can avoid setting one more casing string;improved quality of the cement job in comparison with the not always reliable results of a double stage cementing;operational time and cost reduction.
Open Hole Completions: Drilling Fluid Selection
Authors: Davidson Eric , Stewart Susan 
Published: December 2007

Abstract
Matching reservoir characteristics and completion technology with optimum drilling fluid formulation is important to the economics of any field development. In recent years, this need has become even more important with the growing application of open hole completions in high angle or horizontal wellbores that are now commonly drilled and completed with the same drill-in fluid.
Openhole completions place several demands on the drilling fluids used in the payzone section. In order to maximise benefits, the properties of the fluid need to be optimised for the conditions prevailing in the reservoir. The drill-in fluid needs a rheology good enough to enable good hole cleaning, lubricity good enough to avoid frictional problems, good inhibition with respect to interstitial clays and interceded shales, and, very importantly, to be minimally damaging to the permeability of the formation. Other factors to be considered include completion design and proposed payzone clean up procedure.
The number of potential variables involved means it is very difficult to design a single fluid to cover all eventualities, but a range of alternative drill-in systems has been developed in which each fluid is designed to cover a limited set of circumstances. Most applications can be covered by at least one of the fluids. This paper will discuss four generic drill-in systems, each of which embodies a different approach to achieving the desired properties:water-based polymer systems which may be based on brines of vaiying concentration and which may contain water or acid soluble bridging particlesall-oil systems, covering a wide density rangeaqueous system based on a complex formed between bentonite and mixed metal silicate.solids-free water-based polymer system
Formulations, properties and some examples of field performance are presented together with a discussion of relative advantages and disadvantages of each system type. The objectives of each fluid type are reviewed against actual field experience. Factors influencing selection of fluid type are discussed and guidelines are presented.
Theoretical and Practical Application Guidelines for Using Electrokinetics to Improve Casing Support in Soft Marine Sediments
Authors: Wrixon Robert C. , Cooper George A. 
Published: December 2007

Abstract
This paper presents new results that confirm the potential to solve the problem of offshore structural casing failure by the use of anodic casing consolidation by electrokinetic methods. The specific difficulties in applying electrokinetics to conductive marine sediment are addressed. Increases in bearing capacity and pull-out shear strength of between 100% and 400% were obtained, depending on the level of electrical treatment, for a San Francisco Bay silty clay in both freshwater and saline environments. Experiments performed on shallow clayey sediment samples from the Gulf of Mexico demonstrated that increases in bearing capacity of between 50% and 100% were attainable. The effect of the anode metal on the process has also been investigated, with copper appearing to offer the most benefits for potential offshore applications in terms of current requirement and ultimate shear strength achieved.
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Cuttings Transport Problems and Solutions in Coiled Tubing Drilling
Authors: Leising L.J. , Walton I.C. 
Published: December 2007

Abstract
Coiled tubing (CT) drilling has grown tremendously in the last few years. In spite of the many technological advances that have accompanied this growth, one significant remaining challenge is effective cuttings transport, particularly in deviated wells. This paper presents a summary of cuttings transport problems and current solutions (including fluid selection, flow rates, and operational techniques such as short trips and pumping viscous slugs). It is shown that in many circumstances hole cleaning is more efficient if a low-viscosity fluid is pumped in turbulent flow rather than a high-viscosity fluid in laminar flow. Several detailed case studies are presented that illustrate both severe cuttings transport problems and routine applications without cuttings transport difficulties. The proposed hole cleaning models are used to interpret these data and suggest possible alternative approaches.
Hole cleaning relying on viscous fluids in laminar flow has proved to be inefficient because of the inability to rotate the string to agitate bedded cuttings. Alternatively, a high flow rate for turbulent hole cleaning is more effective, but difficult to achieve because of high friction pressures in the coiled tubing. Therefore, a cuttings bed is almost always present in CT (or any slide) drilling. This has a major operational impact resulting from required remedial activities, increased risk of stuck pipe and the inability to attain the desired reach.
Two novel approaches to understanding hole cleaning are introduced. First, for laminar flow, the distance that a particle will travel (downstream) before it falls across the annulus clearance is calculated using Stokes' law and the local viscosity while flowing. This analysis may be easily applied to optimize mud selection and wiper trips. Applying this model to high low-shear-rate-viscosity (LSRV) gels shows that they may perform well inside casing but are expected to do a poor job of hole cleaning in a narrow openhole horizontal annul us without rotation. Second, for turbulent flow in horizontal wells, the concept of using annular velocity (AV) as a measure of hole cleaning is shown to be insufficient. A more complete term called AVRD is introduced, which is the product of the AV and the square root of the hydraulic diameter. This term should be used to compare cuttings transport in turbulent flow in horizontal wells of different cross sectional areas.
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Co-Operative Approach to Drilling Optimization Yields Better Understanding of PDC Bit Performance in North Sea Program
Authors: Begbie R.J. , Miller B.E. 
Published: December 2007

Abstract
A conventional approach to performance optimization resulted in some PDC performance improvements on the early wells of the Scott Field in Central North Sea blocks 15/21 & 15/22. This approach focused on the development and testing of individual bit features. Highly averaged performance measures such as bit run length and average penetration rate were used to quantify the influence of bit feature changes on bit performance. This approach left some of the variations in PDC performance unexplained. A co-operative drilling optimization study was conducted on two recent platform wells. This paper summarizes the results of the optimization study. focusing on the process and the benefits of identifying root causes of key drillability issues. It is shown that detailed analysis of footbased drilling data could explain many of the observed rate of penetration variances leading to consistently good drilling performance.
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