bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimising Inflow Performance of a Long Multi-Lateral Offshore Well in Low Permeability, Gas Bearing Sandstone: K14-FB 102 Case Study
Authors: Hands Nick , Francis Paul , Whittle Antony , Rajasingam Donal 
Published: December 2007

Abstract
Development well K14-FB 102 was completed as a dual lateral in 1997 to optimise production capacity and reservoir drainage from a tight, Rotliegend sandstone in an offshore gas play in the Dutch sector of the North Sea. The two 5 7/8" horizontal production intervals were drilled and completed openhole using a rheologically engineered, minimal solids, non-damaging sodium formate brine based fluid designed as a drill-in fluid for reservoir intervals. The system was designed around the Low-Shear-Rate-Viscosity (LSRV) which is critical not only for hole cleaning and drilling performance, but also for minimizing filtrate invasion and potential formation damage by using minimal solids. The formate system exhibited superior hole cleaning qualities during the entire interval and no significant drag was observed during drilling. No pills were pumped prior to pulling out of hole and tripping proceeded without problems, verifying excellent hole condition. As a result of high ROP's, a 35% reduction in total reservoir drilling time was achieved. The resulting production capacity was 40% above expectation and a nearzero mechanical skin indicated that the reservoir interval had been completed with minimal residual drilling induced damage. The formate system, with its unique rheological profile, differs from other water-based fluids, and provided advantages not only for drilling technique but also enhanced HSE criteria.
A New Method for Fast and Economical Connection of Large-Diameter Pipe
Authors: Drouin Andre H. 
Published: December 2007

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

Abstract
This paper reviews the history of the design, testing, and field usage of a means of pipe connection that eliminates long and costly field welding of large diameter pipes. Originally developed for connecting drive pipe joints used on jackup drilling rigs, it proved its economy over welding: connections that required three or more hours welding time can be made in a matter of a few minutes. The original connectors first used in the field are still in service after six years having been used repeatedly on a number of wells.
The high logistic costs associated with offshore construction in deeper water where larger pilings are required makes the long welding time on location unbearably expensive. Also, the long stops required for welding make it extremely difficult to restart the pile moving, sometimes requiring jetting or drilling a relief hole, causing even higher cost. This connector cuts this time to a small fraction of that required for welding.

Introduction
Historically, lengths of pipe have been joined together in a variety of manners; the oldest being the bell and spigot joint which is still widely used today. Lengths of pipe are also joined together by threaded collars, integral male and female threads, couplings, flanges, by welding, etc..
Targeted Steam Injection Using Horizontal Wells with Limited Entry Perforations
Authors: Boone Thomas J. , Youck Daryl G. , Sun Sam 
Published: December 2007

Abstract
Limited-entry perforations have been used in vertical wells in both California and at Imperial's Cold Lake field as a method for distributing steam to different zones. The technology relies simply upon designing the number, size and placement of the perforations so that critical or choked flow occurs across the perforations during steam injection, and steam exits the well with the desired distribution. This paper describes an experimental horizontal well where this same technology was used to replace ten vertical injection wells with a single horizontal well. The well was located between rows of vertical wells in reservoir that had been subjected to more than ten years of operations under cyclic steam stimulation. The limited-entry perforations enabled steam to be targeted at the cold regions of the reservoir. A more typical completion such as a screened or slotted liner would not have provided any control over the placement of steam in the reservoir. The 1000 m long liner was cemented in place with a completion design consisting of only 28, 3/8 inch diameter perforations which were drilled through the casing and cement. The design injection rate for the well was 2000 to 3000 m3/day of 70% quality steam. This paper presents an assessment of the performance of the well based on theoretical calculations, measured injection pressures and rates, and 3D seismic imaging.
New Viscosifier for Water Based Muds Based on a Genetically Modified Starch
Authors: Ward I. , Chapman J. W. , Williamson R. 
Published: December 2007

Abstract
A new viscosifier based on genetically modified starch has been developed and field proven. The product, when used in combination with low levels of pre-hydrated bentonite produces drilling fluids with exceptional shear thinning characteristics. Furthermore it has been found that the product, when incorporated at the optimum level for rheology control, also acts as an effective fluid loss control agent. This overcomes the need for separate fluid loss control agents such as polyanionic cellulose or carboxymethyl cellulose. This "one pack" viscosifier and fluid loss reducer offers a commercially viable alternative to conventional systems1.
This paper details the extensive laboratory testing programme required for the development of this product. Formulations based on brines and seawater, including the highly inhibitive silicate based fluid2, are illustrated. The performance of this new fluid is compared with conventional formulations containing xanthan gum and PAC. Data from the early field trials are included.
Correlation of Bubblepoint Pressures for Reservoir Oils--A Comparative Study
Authors: McCain W.D. , Soto R.B. , Valko P.P. , Blasingame T.A. 
Published: December 2007

W.D. McCain Jr., R. B. Soto, P.P. Valko, and T. A. Blasingame

Abstract
None of the currently proposed correlations for bubblepoint pressure are particularly accurate.
Knowledge of bubblepoint pressure is one of the important factors in the primary and subsequent developments of an oil field. Bubblepoint pressure is required for material balance calculations, analysis of well performance, reservoir simulation, and production engineering calculations.
In addition, bubblepoint pressure is an ingredient, either directly or indirectly, in every oil property correlation. Thus an error in bubblepoint pressure will cause errors in estimates of all oil properties. These will propagate additional errors throughout all reservoir and production engineering calculations.
Bubblepoint pressure correlations use data which are typically available in the field; initial producing gas-oil ratio, separator gas specific gravity, stock-tank oil gravity, and reservoir temperature. The lack of accuracy of current bubblepoint pressure correlations seems to be due to an inadequate description of the process - in short, one or more relevant variables are missing in these correlations.
We considered three independent means for developing bubblepoint pressure correlations. These are (1) non-linear regression of a model (traditional approach), (2) neural nelwork models, and (3) non-parametric regression (a statistical approach which constructs the functional relationship between dependent and independent variables, without bias towards a particular model).
The results, using a variety of techniques (and models), establish a clear bound on the accuracy of bubblepoint pressure correlations. Thus, we have a validation of error bounds on bubblepoint pressure correlations.
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Morrow-Springer Pressures of the Anadarko Basin
Authors: Davis Herbert G. , Nondorf James L. 
Published: December 2007

ABSTRACT
The Morrow-Springer pressures in the Anadarko Basin have become a major factor in the exploration and exploitation of the Basin's major pre-Permian gas reserve. The tectonics affecting the Morrow-Springer formations during and after deposition of the sediments may be partly responsible for the abnormally low and high pressures in their respective areas. Isopach maps of the Morrow-Spriinger indicate the major divisions of pressure gradient in the formations. BHP gradient maps can be interpreted in areas where control is available with knowledge of the thickness of unit to be penetrated and the amount of reservoir rock anticipated. To date 5000 to 6000 feet of Morrow-Springer has been penetrated in the 'deep' basin. BHP's to 10,000 psi can be predicted however extensive geophysical and geological research are required to resolve the complex south flank of the Anadarko Basin with greater BHP's.

INTRODUCTION
The Morrow-Springer pressures in the Anadarko Basin have become a major factor in the exploration and exploitation of the Basin's major pre-Permian gas reserve.
In the fifties and early sixties little was known of the pressure system of these formations and exploration had reached 'boom' proportion as the drillbit continued to discover gas in the Lower Pennsylvanian.
Figure I illustrates the Anadarko Basin in its tectonic location, bounded on the south by the buried Amarillo-Wichita Mountains; on the west by the Sierra Grande Uplift; on the northwest by a minor arch in Pennsylvanian time, the Las Animas Arch, which we like to use as the separation between the Anadarko Basin and the Denver Basin; on the north by the Central Kansas Uplift; and on the northeast by the Nemaha Range.
Environmental and Safety Regulations in Sour Gas and Crude Operations
Authors: Ehrhardt C.D. 
Published: December 2007

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

Abstract
Because of the harmful effects of hydrogen sulfide, drilling and producing operations involving sour gas and crude are subject to special regulations. These vary from state to state. Environmental regulations which control sulfur recovery plant operations are especially severe. plant operations are especially severe. Regulations applicable to the states bordering the Gulf of Mexico and to the Gulf are discussed. Technical, professional and management people involved in such operations must be familiar with the hazards and with the regulations.

Introduction
The dangers of hydrogen sulfide to humans, the environment, and to equipment have long been recognized. It is toxic, flammable, explosive and corrosive. Studies by the Bureau of Mines and the Texas Medical Association of the hazards of sour gas date back into the 1920's. In the earlier days of sour gas and oil operations, operators depended upon selfregulation. Gradually, health and Industry associations provided guidance which made for safer operations. More recently, many regulations have been adopted by various governmental agencies to require all stages of sour operations to conform to safety and environmental standards.
This presentation is not intended to be a complete and finer reference on all of the applicable regulations, since the regulations are too lengthy, complex and changing; rather, it is intended to give an overall view of this aspect of regulation, and to permit a quick review of the regulations in permit a quick review of the regulations in effect in different areas. Regulations in the states bordering the Gulf of Mexico and the Gulf will be discussed.

HARMFUL QUANTITIES AND DEFINITIONS
The concentration of hydrogen sulfide which constitutes a harmful quantity depends upon the subject being considered, whether humans, the environment or equipment, and upon the body or agency setting the standard.
A New Approach for Modeling Horizontal Well Singularities in Petroleum Engineering
Authors: Guevara-Jordan J. M. , Fermín A. K. , González R. J. 
Published: December 2007

Abstract
We propose a new methodology to evaluate the transient pressure distribution of horizontal wells with any curvilinear trajectory in isotropic/anisotropic reservoirs of arbitrary shape. This is based on the mathematical representation of the tortuous horizontal wellbore using a generalized function. A novel method for removing the singularities involved in the generalized function allows the reduction of the original problem to the standard solution of the homogeneous diffusivity equation with reformed initial condition and boundary values. This new approach combines the Green function method and any standard numerical technique in a single computational strategy to obtain the transient pressure response generated by a curved/twisted horizontal well in oil reservoirs with irregular frontiers.
Stochastic Formulation for Uncertainty Assessment of Two-Phase Flow in Heterogeneous Reservoirs
Authors: Dongxiao Zhang , Liyong Li , Tchelepi Hamdi A. 
Published: December 2007

Abstract
In this paper we use a direct approach to quantify the uncertainty in flow performance predictions due to uncertainty in the reservoir description. We solve moment equations derived from a stochastic mathematical statement of immiscible nonlinear two-phase flow in heterogeneous reservoirs. Our stochastic approach is quite different from the Monte Carlo approach. In the Monte Carlo approach, the prediction uncertainty is obtained through a statistical post-processing of flow simulations, one for each of a large number of equiprobable realizations of the reservoir description.
We treat porosity and permeability as random space functions. In turn, saturation and flow velocity are random fields. We operate in a Lagrangian framework to deal with the transport problem. That is, we transform to a coordinate system attached to streamlines (time, travel time, and transverse displacements). We retain the normal Eulerian (space and time) framework for the total velocity, which we take to be dominated by the heterogeneity of the reservoir. We derive and solve expressions for the first (mean) and second (variance) moments of the quantities of interest.
We demonstrate the applicability of our approach to complex flow geometry. Closed outer boundaries and converging/diverging flows due to the presence of sources/sinks require special mathematical and numerical treatments. General expressions for the moments of total velocity, travel time, transverse displacement, water saturation, production rate, and cumulative recovery are presented and analyzed. A detailed comparison of the moment solution approach with high-resolution Monte Carlo simulations for a variety of two-dimensional problems is presented. We also discuss the advantages and limits of applicability of the moment equation approach relative to the Monte Carlo approach.
Internal Tubular Plastic Coatings for Sour Gas and Crude Service
Authors: Voyles Jack L. 
Published: December 2007

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

Abstract
Baked phenol-formaldehyde formulations, commonly referred to as baked phenolics, have had varying degrees of success in H2S environments. The degree of success for a given baked phenolic used as an internal tubular coaling depends upon H2S concentration, pressure, and temperature of the environment. Laboratory tests of baked phenolic coatings indicate 5% H2S, 2,000 psi, and 200 degrees F to be the upper limits for satisfactory performance. Case histories have proven certain individual formulations are capable of performing satisfactorily above these limits.

Introduction
Coating material formulations for H2S environments of high pressure and temperature are achieved by combining inert fillers with thermosetting phenolic resins. The type and amount of filler used in baked phenolic coating materials influence the temperature limit, acid resistance, flexibility, permeability and gas diffusion rate. A baked phenolic coating well balanced in the preceding five points will perform well in continuous service points will perform well in continuous service above the limits of most manufacturer recommendations. Extensive laboratory and field tests are necessary to determine the performance capability of a baked phenolic coating in an H2S environment.

REQUIREMENTS IN COATING APPLICATION
Proper application is essential to produce a satisfactory coating performance in service The following are necessary steps to achieve proper coating application. proper coating application.Adequate metal cleaning for internal tubular coating requires flint blasting to an SSPC-SP-5 (white metal finish).An anchor pattern (1 1/2 to 2 mils)is required to obtain a satisfactory bond of coating material to the steelsubstrate.A uniform coating film well balanced in adhesion and cohesion produces a product that will not delaminate or lose bond with the steel substrate.
Sulfur Recovery from Sour Natural Gas: A Review of Gas Treating/Claus Plant Design and Operations
Authors: Goar B. Gene 
Published: December 2007

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

Abstract
The decision to build a sour natural gas treating facility for the purpose of sweetening the gas and recovery of elemental sulfur involves many considerations, and usually represents a significant investment. Selection of the optimum gas treating process and sulfur recovery scheme may to a process and sulfur recovery scheme may to a complex problem. Many well established criteria are important to consider during the design phase of such a project. Subsequent operation of these facilities requires a good knowledge of potential problem areas.
This paper is a general review of the main factors that should be considered in the selection, design, and operation of a gas treating/sulfur recovery facility.

Introduction
Today we are facing a serious energy crisis in this country. All available natural gas reserves will be needed in the future. Some operating companies are reluctant to produce sour gas wells today, because of the high cost of treating the gas to remove H2S and other contaminants to meet sales gas specifications. This picture is changing rapidly as the price for gas increases and the supply of available energy dwindles.
In the past (1965–1970), an added incentive for treating sour gas was recovery of the elemental sulfur. At present, the market situation for sulfur is not very favorable. The supply is plentiful and the price is somewhat depressed. However, the price is somewhat depressed. However, the future looks brighter. About 50% of all sulfur produced in the U.S. and Canada is consumed in the manufacture of fertilizers. Since the world population growth and need for fertilizers is on the incline, it is probably safe to assume that the price for probably safe to assume that the price for sulfur will follow an upward trend in the future.
Once a sour gas well is drilled or a "sour gas field" drilling activity is completed, the producer must consider such questions as:Is it more economical to lay a sour gasline to the nearest gas treating plant, which may have excess capacity, and pay a treating cost to have the gas sweetened?Or, is it more economical to lease equipment for on-site sweetening?
Drillstem Maintenance in Sulfide Environments
Authors: Mauzy Harry L. 
Published: December 2007

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

Abstract
Sulfide stress cracking (SSC) is a major obstacle to the successful drilling and completion of deep wells in sulfide environments. The mechanism of SSC is described and the current status of SSC resistant steels is reported. Precautionary measures to avoid or control SSC are enumerated.

Introduction
A major obstacle to the successful drilling and completion of deep wells is the increasing frequency of sour environments as deeper horizons are penetrated. While sour environments can cause trouble at any depth, higher strength steels required for deep drilling are more susceptible to failure than steels normally used for shallow wells and the deeper environments may be even more hostile.
The sudden catastrophic failure mode experienced in sour environments is termed sulfide stress cracking (SSC), and is characterized by flat, brittle failures with little visible corrosion and no detectable plastic deformation. These failures occur plastic deformation. These failures occur while operating at apparently safe load levels and often after extended periods of satisfactory performance.
In the 20 to 25 years since the epidemic of drillstem failures in the Jumping Pound and Pincher Creek fields in Canada and Pound and Pincher Creek fields in Canada and the Lacq field in France focused attention on material performance in sour environments, extensive investigations have conclusively shown that SSC is a severe form of internal hydrogen embrittlement, accentuated by the presence of hydrogen sulfide (H2S). presence of hydrogen sulfide (H2S).

MECHANISM OF SULFIDE STRESS CRACKING
Atomic hydrogen (H), generated in drilling fluids by corrosion processes, bacterial action, or thermal degradation of organic additives, can be absorbed into and diffuse through the steel crystal lattice. In the absence of H2S, atomic hydrogen quickly forms molecular hydrogen (H2) that cannot be absorbed. The presence of H2S greatly decreases the speed of recombination of H to H2, thereby increasing the amount of atomic hydrogen available for absorption.
After being absorbed into the steel, the atomic hydrogen migrates to and accumulates at the region of highest stress usually just below the root of a thread, notch, section change, or other discontinuity.
New Automated Continuous Gas-Lift Control System Improves Operational Efficiency
Authors: Bergeron Terry , Cooksey Andrew , Reppel J. Scott 
Published: December 2007

Abstract
The gas lift injection rate and its correlation to the oil production rate has been well established. State-of-the-art electronic flow controllers are now being employed to improve the efficiency of the injection process in gas-lifted applications so that the profitability of the wells can be increased. These control systems, which integrate modern electronic flow measurement methods with proportional-plus-integral-plus-derivative (PID) control, generally result in an improved return on investment for gas lift installations.
This paper presents field data for an automated continuous gas-lift control system that illustrates how a more efficient use of injection gas results in lower injection costs, and in some cases, increased oil production. Case No. 1 confirms the benefits of maintaining a constant injection rate by regulating the production. This case also supports the theory that once a certain gas injection rate is reached, additional injection will not yield additional oil production.
Case No. 2 discusses a remote single-well application that suffers from lost production because of injection line freezing at the injection choke and will illustrate how the use of electronic gas-lift controllers eliminated the problem.