bluuebunny/crossref_metadata_2025 huggingface dataset:
Heavy Oil Reservoir Management
Authors: Thakur Ganesh C.
Published: December 2007

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

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

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

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

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

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.

P. 77
Cuttings Transport Problems and Solutions in Coiled Tubing Drilling
Authors: Leising L.J. , Walton I.C.
Published: December 2007

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.

P. 7
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

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.

P. 935
New Generation Drill String Safety Valves
Authors: Tarr B.A. , Luy R. , Rabby G. , Kickermann H. , Senftleben J. , Cunningham J.
Published: December 2007

Drill String Safety Valves (DSSV's) are considered as part of the essential well control equipment on every rig but they are currently only addressed in a very limited fashion in industry specifications. Performance problems with DSSV's in stripping operations motivated Mobil to lead an industry effort to develop appropriate functional specifications for consideration by API and to conduct performance testing to establish that new generation valves could be built to meet the proposed new specifications. Results from testing three new generation valves indicate that common DSSV performance problems can be addressed and the proposed new specifications are workable.

P. 231
Drill String Management to Reduce Drilling Risks
Authors: Summers M.A. , Crabtree S.R.
Published: December 2007

Increases in recent and projected rig activity are putting tremendous strains on current inventories of drilling tools and on the industry supply chain attempting to bolster those inventories. Additionally, while much of the new activity is centered in established oil provinces and using established technologies, many projects are on the frontier, both in terms of their graphical location and their technology applications. The frontier projects often must deal with strained supply lines and makeshift local infrastructure as well as down hole tool stresses which were never envisioned when the tools were first introduced.

The linkage of high demand with limited supply can result in a tendency to accept lower quality materials to increase availability and meet drilling schedules. This often increases the risk of drill string failures and associated cost overruns due to lost time, lost hole, lost tools, fishing and sidetracks.

This paper will explore how drill string management techniques have addressed these inventory and infrastructure issues with the objective of mitigating drilling risks. Case histories are reviewed where various actions have been formulated to meet the specific demands of frontier drilling projects and the drilling cost savings that have resulted.

P. 287
An Analysis of Failures in Coiled Tubing
Authors: Stanley Roderic K.
Published: December 2007

This paper outlines and discusses failures in carbon steel coiled tubing (CSCT), along with their causes, and proposes methods for de-rating used coiled tubing that might be applicable to an industry recommended practice.

P. 515
Smart Centrifuge for Solid Answers to Solids Control
Authors: Phillips Victor
Published: December 2007

The decanting bowl centrifuge is an accepted tool in drilling fluid solids control and has been in use since over 30 years. Initially the centrifuge was intended as a means to recover barite from drilling mud; but now, the expected uses of this type of machine is quite varied. In general, this discussion will describe the evolution of the control of the decanting bowl centrifuge. A discussion of multilevel microprocessor controlled centrifuge here will describe some of the benefits, results and new capabilities which have been developed.

P. 743
Increasing Production and Profitability by Use of a Computer Monitoring Program Inc.
Authors: James Jerry , Huck Gene
Published: December 2007

Profitability is normally maximized from oil and gas properties when maximum production rates are consistently obtained. The computer program discussed in this paper has been developed to help small operators realize that goal with a minimal time investment
Optimization of the Performance of High-Permeability Fractured Wells
Authors: Aggour Tamir M. , Economides Micheal J.
Published: December 2007

High-permeability fracturing (frac&pack) has become a major new stimulation treatment, intended to improve well performance and not just to control sand production. Viewed as such, an optimization is warranted balancing the size of the fracture with incremental well performance. Analogous schemes have been introduced in unrestricted fracturing for low-permeability formations, using the fracture half-length vs. the net present value (NPV) as the optimization criterion. While a physical optimization for all fractures, suggested by many, implies a dimensionless conductivity around unity, such a value may neither be possible nor economically attractive in high-permeability reservoirs. We are presenting here a scheme, combining high-permeability fracture modeling with expected well performance which, along with the NPV calculation, leads to a three-dimensional Optimization. This optimization, allowing fracture half-length and width variation, provides the optimum width for each fracture length and the global optimum for all lengths at which the NPV is maximum. Treatments should be designed for the optimum width and length combination. Parametric studies are done with post-treatment skins (other than the theoretical negative values) denoting the major impact of fracture face damage and fracture-well connectivity.

P. 481
Advisory Boards: Leveraging Industry Resources
Authors: Wiggins Michael L. , Broussard Neal J. , Rieke Herman H.
Published: December 2007

Many petroleum engineering programs have instituted industry advisory boards during the last decade. These boards are designed to assist the petroleum engineering program in meeting the needs of petroleum engineering education and industry. This is accomplished by providing the programs with access to industry resources of manpower, capital, equipment and facilities. Properly used these resources can be leveraged far beyond those readily available to an individual program. An active board, with a committed faculty, can help develop a respected and successful education program within the petroleum community This paper presents a general overview of advisory boards and how they can be utilized in an effective manner.
Stress Concentration Induced in Elastic Rocks Under a Diamond Bit Tooth
Authors: Duc N. Guyen Minh , Cholet H. , Tricot P.
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 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 who 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 request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

As an attempt to clarify the working process of drag bit blades, a plane stress process of drag bit blades, a plane stress analysis on a static model has been made by photoelasticity and interferometry. photoelasticity and interferometry. Induced stress concentration, lines tangent to critical directions of supposed preexisting cracks, and fracture initiation zones are described in the vicinity of the contact area.

It leads from this study to the following conclusions; first, for stress distributions in the cutting mechanism.

High tensile stresses appear around the cutting edge. Their magnitude increases as the cutting angle increases and does not depend on the clearance angle. When the value of the ratio of the cutting edge curvature radius to the groove depth is high, the compression zone spreads in the direction of the resulting applied force. The greater r/t is, the closer this occurs to contact. High-compression stress concentrations are induced under the tooth for clearance angles other than zero. Their magnitude increases with rake angles.

In the grinding mechanism a double compression stress state is perceived in the vicinity of contact. Tensile stress appears behind the tooth, and high-compression stresses are propagated in front of it. propagated in front of it. Second, from the Griffith-Walsh failure initiation theory and the discussions of the fracture initiation patterns, in the cutting case, tooth efficiency is determined according to horizontal force, FH, with the following results.

The bit is more efficient when the rake angle increases. The clearance angle has no significant effect on fracture initiation. The drilling rate improves when the ratio between the cutting edge curvature radius and groove depth decreases. It may be postulated that a high value of dry Coulomb friction along the cutting face will decrease efficiency.

In the grinding case, for a given vertical force, friction increases tooth efficiency. For both of these mechanisms, ratio ET/EM has no significant effect.
Optimizing Field Compressor Station Designs
Authors: Pennybaker Kent A.
Published: December 2007

The main reasons for optimizing new field compressor station designs and for upgrading existing stations are safety considerations, environmental impacts, and economics. With a well designed compressor station it is possible to improve safety and environmental conditions while saving capital and increasing income.

A well designed compressor station will be able to reduce the venting of heavy hydrocarbons from storage tanks, which can increase safety by reducing the possibility of forming explosive vapor clouds near venting tanks. An optimized design can improve safety by reducing the amount of hydrocarbon inventory located at the site. This can also save money by eliminating the need for a site to be covered by OSHA's Process Safety Management.

Improving the environmental conditions by reducing the venting of hydrocarbons from the station's storage tanks is another advantage of a well designed compressor station. The exhaust pollution can also be reduced by utilizing less compressor horsepower and reducing the trucking needs for station supplies and products such as methanol and condensate.

The economic advantages of an optimized compressor station include reduced operating costs and maximized product recovery. Reduction in operating costs are achieved through fuel savings from reduced horsepower requirements and reducing trucking costs. Maintenance activities are also typically less due to less horsepower, freeze ups, etc. Reducing the venting requirements means more gas is recovered as product, resulting in more income.

Evaluating and selecting the best configuration for a compressor station design is an important decision. Many schemes have been evaluated for different situations and compared so that the most cost effective configuration can easily be selected for new or existing station designs.
Hydraulic Fracturing in High Permeability Wells
Authors: Al-Haddad S. , Arbaugh R. , McKnight D.
Published: December 2007

Traditionally, formations with permeabilities greater than 100 md are not considered as candidates for hydraulic fracturing stimulation. This perception is based on the idea that the increased effective wellbore radius is not needed in high permeability formations.

This paper proposes that, if properly designed and performed, hydraulic fracturing benefits extend beyond the increased effective wellbore radius. These benefits include; extending the wellbore beyond the drilling damaged zone eliminating the need for further stimulation, increased productivity in wells limited by drawdown, and increased productivity with a higher flowing bottom-hole pressure which hinders water encroachment in edge water drive systems.

This work is based on field data and computer simulations from the Gulf of Mexico area. These high permeability wells were hydraulically fractured and gravel packed using the FracPac system. Fracture design and operational implementation strategy, including post completion flow rate and period, will be presented in this paper. Moreover, NODALTM analysis, well test, and production data will be presented. Well test and production data have shown that hydraulic fractures associated with the sand control system, have significantly impacted wells' performance and achieved the desired objectives.

P. 321
A New Concept for On-the-Fly Hydration of Water-Based Fracturing Fluids
Authors: Gupta D.V. S. , Pierce R. G.
Published: December 2007

On-the-fly hydration of polymers used in water-based fracturing has been well accepted in the industry. Conventional technology to date has utilized a residence time of about 4 minutes to achieve this. In this paper, we describe a new concept based on high shear which reduces the residence time requirement to less than 20 seconds, which makes the system a real on-the-fly system. In addition, of the smaller residence time, minimizes the need for disposal of fluids in case of premature job termination.
Gas Recovery Is Increased With Prudent Application Of Wellsite Stripper Compressors In Southern Alberta, Canada
Authors: Hahn D. , Moss C. , Sood S. , Carley D.
Published: December 2007

Many gas gathering systems in Canada operate at pressures above 1000 kPa (145 psi) which could result in premature abandonment of gas wells and pools. PanCanadian Resources has selectively identified numerous opportunities to recover this additional gas and increase productivity by installing wellsite stripper compressors.

A systematic approach was used to identify and select 19 wellsite compressor applications. Two of the primary criteria used on this initial screening was a well's cumulative production and its peak production rate. The selection process then required further reserve and well performance analyses and utilized material balance and nodal analysis techniques. The hardware selection process concentrated on the ability to approach atmospheric pressure at the wellhead. These lower wellhead pressures resulted in incremental gas recovery and improved wellbore hydraulics whereby liquids are effectively lifted due to increased tubular velocities.

The applications to date have been predominantly wells with higher deliverability capability in depleted reservoirs. The program has resulted in sustained incremental production of 323 E3 m /D (11.4 MMSCFD) and an additional 378 E6 m3 (13.3 BCF) of gas recovery. The success of this program will be expanded to other gas applications where lower pressures will benefit a well's or group of wells' productivity and ultimate gas recovery.

P. 381
A Critical Evaluation of Gas Monitoring Systems as Currently Implemented in Hydrocarbon Drilling Operations
Authors: Drnec M.L. , Spoerker H.F.
Published: December 2007

Surface gas measurements to identify gas bearing zones have been in use since the 1920s. Early well-site sampling methods were inaccurate and inconsistent, but had little effect on results since measurement and analysis methods were equally poor. The introduction of gas chromatography in the 1950s created the demand for gas samples more representative of the gas content of the drilled formation. New techniques were developed, but even these methods of continuous gas extraction at the well site were recognized to be inconsistent. However, the basic gas extraction system developed then is still in use in the field today. The paper presents a critical evaluation of on-line gas monitoring systems as currently used in the drilling industry. A more efficient real-time monitoring system that combines state-of-the-art technology with established sampling elements has been developed. Special emphasis was put on the adaptability to oilfield operations. Qualitative and quantitative interpretation of the monitoring results are presented and field experience with the new system is evaluated. Recent case studies are critically discussed with an approach to formation evaluation and the correlation between well logging and gas logging. The presented gas monitoring system provides good performance under field conditions and yields representative results for the definition of the bottomhole gas signature. The results of the gas logging operation - if applied correctly - prove to be a valuable basis for volumetric gas analysis and subsequent well testing, thus time and cost reduction is achieved. Mobile and rugged technology, fast rig up and low maintenance make the system very flexible and customer friendly.

P. 387
Composite Coiled Tubing in Harsh Completion/Workover Environments
Authors: Rispler K. , Berning S. , Fowler H.
Published: December 2007

Recent advances in the development of large-diameter and high-strength steel coiled-tubing (CT) products have helped fuel growth in the coiled-tubing industry. Advanced spoolable composite CT may offer advantages in some applications to the industry over current steel products. Composite CT could expand the market for coiled-tubing service and well completion. The composite CT's resistance to corrosion from CO2 and H2S should make it readily applicable in injection, disposal, and producing wells in which current tubular installations demonstrate limited lifespans or where costly corrosion-protection systems are used. The composite CT may be a cost-effective alternative to 13-chrome and glass-reinforced epoxy (GRE) jointed pipe. Because composite CT is resistant to chemical stimulation fluids such as HCl in sweet and sour wells, the tubing may be more reliable than conventional tubing, and may provide a cost savings in larger treatments such as those used in horizontal stimulations.

P. 405
The Allocation of Gas Well Production Data Using Isotope Analysis
Authors: Bazan L. W.
Published: December 2007

Geochemistry, specifically gas chromatography and isotope analysis, offers a solution to the problem of properly allocating gas production to specific reservoirs when more than one formation is commingled in a well. Current allocation methods involving zone isolation are limited because the commingled flow rates obtained on the surface are not necessarily representative of actual individual formation contributions.

The proposed solution to this problem was the derivation of three models that accounts for variable isotope and composition characteristics, while also providing a trend in which all such data could be correlated. Isotope analysis in this application involves obtaining the geochemical "fingerprint" of a natural gas sample using detailed chemical and isotopic characteristics of the gas sample.1 From these models, it is possible to determine a commingled production allocation from calculated isotope data, given only the gas chromatography results, specifically the composition and specific gravity of a given sample.

This approach will permit adjusting the commingled production allocations over the life of the well under changing reservoir conditions. Once each13C endmember is established, the fingerprint remains constant for the life of the well. Early data suggests that the use of isotope analysis to determine production allocations should produce accurate results once a calibration technique is established
Numerical Simulation of Proppant Accumulation at Fracture Wall due to Fluid Leak-off
Authors: Weng X. , Klein H.H.
Published: December 2007

Proppant concentration variation in a hydraulic fracture across the fracture width is investigated using a slurry transport simulator. The result indicates that the proppant slurry dehydrates more near the fracture walls and thus has higher concentration at the wall than at the center of the fracture width. When fluid leak-off is high, this can lead to a proppant pack built on the wall, reducing the effective width of the flow channel and causing mid-fracture screen-out. Furthermore, since the slurry dehydration occurs mostly near the fracture wall, the slurry that travels down the middle of the fracture dehydrates slower than what the current hydraulic fracture models would predict based on the assumption of uniform slurry concentration across the width. Therefore, in tip-screen- out (TSO) designs, it may take longer to achieve TSO than what models predict. The effect of a localized high leak-off area within a fracture, which may represent faults or reservoir inhomogeneity, is also investigated. Again, proppant wall- building occurs and causes width restriction.

P. 615
Measurements Of Multiphase Fluid Flow
Authors: Nicolas Y. , Witterholt E.J.
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 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 who 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 request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A primary research facility has been constructed by EPS* in their laboratory at Clamart, France, for the investigation of multiphase-flow phenomena in vertical pipes. This flow loop is capable of circulating pipes. This flow loop is capable of circulating multiphase combinations of gas (air), oil, and/or water, at controlled rates through vertical pipe of variable cross section. The first application of the Clamart flow loop is in the design, development, and evaluation of new flow-measurement devices for Production Logging services. A second and equally important application has been the study of multiphase flow phenomena per se. In Production Logging measurements involving two-phase flow, the crux of the interpretation problem is the estimation of slip velocity. (Slip velocity is the rate at which the lighter phase rises relative to the heavier fluid.) Investigations have been carried out to determine the effects of fluid properties and flow rates upon slip-velocity determination in two-phase flow. The bubble velocity-holdup-slip velocity relationships are examined, and comparisons are made of Clamart experimental findings with other models and descriptions of two-phase tow. In particular the dependence of bubble-rise velocities on interfacial tension and of slip velocity on holdup are exhibited. Considering the complexity of multiphase-flow phenomena, the agreement between mathematical models and experimental data is quite good.

P. 1
Experimental Fireflood in a Very Viscous Oil-Unconsolidated Sand Reservoir, S.E. Pauls Valley Field, Oklahoma
Authors: Elkins Lincoln F. , Morton Dick , Blackwell William A.
Published: December 2007

This field produces 8000 cp 100 API oil by natural water drive from an unconsolidated sand reservoir about 100 feet thick. Nearly all wells produced 10–50% sand initially, declining later to 0.1–2%, regardless of completion method. Apparently this production of sand created inter-connecting "worm hole" porosity extending at least between wells on porosity extending at least between wells on 10-acre spacing. Some of the evidence for this during primary production was:

1 near-gauge caliper surveys of open hole sections after production of large volumes of sand;

2 rapid movement of injected water and tracers between wells; and

3 production of Jelflake lost circulation material from two wells following its use in workover and deepening of a third well.

Air was injected below the oil-water contact in an edge well as a partial test for spontaneous ignition in a peripheral fireflood. In about four months some offset wells were converted to flowing after breakthrough of "air" devoid of oxygen but also containing very little carbon dioxide. When produced "air" reached high oxygen containing test was stopped. Later a structurally high 'Well was ignited. Extremely rapid travel of carbon dioxide to 2 offset wells was also indicative of inter-connected "worm hole" porosity created by production of sand.

The fireflood stimulated two offset wells such that total field production increased from 100- to 170 BOPD previously to a maximum 400 BOPD six months later and averaged 310 BOPD for the 16 months of air injection. Cumulative average air-oil ratio was 6 Mcf/bbl. Although the test was physically successful, abnormally high physically successful, abnormally high producing well operating expense precluded producing well operating expense precluded continuing operation and expansion of the project.

Introduction

The Southeast Pauls Valley Field, Garvin County, Oklahoma, producing from the oil Creek Sand at a depth of 4300 feet, 'Was discovered in March, 1955. Since it produces very viscous oil from unconsolidated sand, operating problems have been severe.
Log Derived Rock Properties For Use In Well Stimulation Design
Authors: Anderson Terry , Walker Terry
Published: December 2007

Well logs which present the full wave train of the acoustic signal show variations in both the compressive and shear wave arrivals with lithological changes. This information, along with elastic constants, which can be derived from the logs, can be used in the design techniques available for well stimulation planning.

This information has been successfully applied in one area of California to select completion intervals that could be successfully stimulated at pressures below wellhead limitations. Additionally, pressures below wellhead limitations. Additionally, this data could be applied to the prediction of fracture height and of the fracture closure or sand embedment problem where productivity increases from well stimulation are only temporary.

Introduction

Optimization of well treatment over recent years has necessitated more exact input data regarding the formation characteristics. Design techniques have been developed which require specific rock properties; however, many of the properties used properties; however, many of the properties used are assumptions or average values obtained from limited core samples. Variations of geological factors under downhole conditions are readily observed on many types of logs; however, many of these variations are seldom taken into account in treatment design. Their influence on vertical fracture height is an important consideration for which there has been nothing very consistent in the method of prediction.
Relative Tax Generation Of Shale Oil Plants Versus Foreign Crude Importation
Authors: Schanz John J , Brightwell Thomas P. , Prien Charles H.
Published: December 2007

One of the attractions of development of domestic resources is the public revenues that are generated from the bonuses, royalties, and taxes public revenues that are generated from the bonuses, royalties, and taxes that result from the activity. While many are aware that government revenues are involved, only those directly involved make an effort to estimate their magnitude. For the producer taxes are a matter of considerable concern because of the impact on his costs and after-tax income. For the government official it is both a new source of income as well as an activity that will create demands against public funds. The objective of this paper is to estimate the magnitude of public revenues that are involved in one year's operation of a 100,000 barrel a day shale oil plant in Colorado. These revenues are then contrasted with those that result from the importation of an equivalent amount of crude oil from a foreign source. Finally, the various economic advantages and disadvantages that are involved for the producer, governmental units, and the U.S. consumer are reviewed. To estimate public revenues to be derived from a national resource that will be produced in the future using an untested technology involves a considerable amount of speculative judgment or estimation. Even the most fundamental data—such as product prices and costs—are not available. In view of the uncertainty and the judgmental character of the oil shale data, three examples will he presented:governmental revenues assuming that the firm achieves a certain return on invested capital;revenues.
Potential Underground Storage of Hydrocarbons Along the Eastern Seaboard
Authors: Langill Richard F. , Heckard John M.
Published: December 2007

This paper was prepared for the Eastern Regional Meeting to be held in Columbus, Ohio, November 8–9, 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 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.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Many areas of the United States are suitable for the underground storage of hydrocarbons from both a geologic and an economic viewpoint. This potential for underground storage has not been explored or developed to any great extent along the eastern seaboard, although the need for underground storage continues to increase.

A growth in demand for clean fuels and changes in the availability of domestic natural gas supply for the eastern seaboard point to a present need for evaluating the potential for underground storage of gas supplies from other sources. Specifically, aquifer storage facilities for natural gas derived from domestic or imported sources and from increasing imports of liquefied natural gas, should be developed for both curve-shaping and peak-shaving requirements. This aquifer storage could be used to meet increasing gas demands resulting from population growth, particularly in inland areas excluded particularly in inland areas excluded from ready deliverability provided by LNG vaporization facilities. In addition, the same aquifer storage facilities could find a future use in handling supplies of gas from domestic synthetic natural gas.

Cavern storage of LPG or reformed products for the northeast should also products for the northeast should also be developed. Cavern storage would handle increased demands for products such as propane, butane, naptha, fuel, oil and propane, butane, naptha, fuel, oil and crude. The total potential for cavern storage has not been adequately assessed in terms of future needs.

The technical feasibility of both aquifer and cavern underground storage depends largely upon geologic conditions. The economic feasibility can readily be estimated by comparison with other storage operations. An analysis is made of existing geologic conditions (on a regional basis) and specific recommendations are made relative to the development of underground storage facilities along the eastern seaboard.