bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Analysis and Field Testing of a Compact Dual-Piston, Hydraulic Sucker Rod Pumping Unit
Authors: Evans R. D. , Weaver P. 
Published: December 2007

ABSTRACT
An analysis and evaluation of a new conpact dual acting piston hydraulic sucker rod pumping unit is presented. The hydraulic unit offers some unique advantages over that of a conventional rotary beam unit. In particular stroke length and speed are readily changed by simple adjustments made to the hydraulics. For deep wells larger hydraulic piston cylinders are interchangable without having to replace the entire unit in order to meet pumping requirements. Performance data is presented which compares the hydraulic unit against selected conventional rotary beam pumping units. The performance analysis is based upon an optimum sucker rod design for a beam unit as a function of producing depth.
Comparison of the hydraulic unit against conventional beam pumping units are made for the following cases; (1) a 72 inch stroke hydraulic unit operating at a constant pumping speed versus API 80 and API 114 beam units, (b) a 96 inch stroke hydraulic unit operating at constant pumping speed versus API 114 and API 160 beam units, (c) a 144 inch stroke hydraulic unit operating at a constant pumping speed versus API 228 and API 320 beam units. In each of these cases the beam pumping units were assumed to be operating at optimum pumping speeds for a given pump setting depth.
To asist in the performance evaluation of the hydraulic unit versus that of a conventional beam pumping unit a 72 inch stroke hydraulic unit was installed in a well of depth 3800 feet located in Payne County, Oklahoma and operated for a period of 14 months. During this time numerous accoustical well sounding and dynamometer tests were performed on this unit as a means of monitoring its performance. Simultaneously, an offset well with identical downhole lifting equipment producing from the same depth and equipped with an API 114 beam pumping unit was monitored with the same test equipment. Field dynagraph cards and their analysis are presented which provided a quantative comparison of the hydraulic unit versus the beam unit.
From the performance analysis and the actual field tests of the dynamometer and acoustical well sounding information the results obtained verify that the hydraulic unit is superior to that of a conventional beam pumping unit over a wide range of operating conditions. In particular, the hydraulic unit will normally operates at lower rod stresses and at the same-time move more fluid since the pumping efficiency of the hydraulic unit exceeds that of the beam pumping unit. This fact is verified by the near ideal dynagraph obtained for the hydraulic unit.
Other advantages of the hydraulic unit including economic considerations are discussed as well as potential applications where the hydraulic unit will offer distinct advantages over its beam counterpart.
Log-Derived Evaluation of Gas-Bearing Cherokee, Red Fork, and Morrow Formations, Custer County, OK
Authors: Busch E. A. , Sobkowich K. N. , Neill B. E. , Sinha A. K. , Fertl W. H. 
Published: December 2007

ABSTRACT
Medium to low porosity and rather tight Cherokee, Red Fork and Morrow sands, located in Oklahoma, contain significant hydrocarbon resources.
To evaluate the commercial importance of wells drilled in Custer County, Oklahoma, an innovative digital shaly sand analysis approach (CLASS® – Epilog®) has been applied, which provides information on total and effective reservoir porosity, total and effective fluid distribution based on the Waxman-Smits equation, shaliness, clay typing, and reservoir productivity.
Several field case examples are presented and discussed based on (1) open hole logging suite, consisting of induction, compensated density/neutron and SpectralogSM, (2) CLASS® analysis, (3) well completion and stimulation data, and (4) the resulting production test results.
Use of Capillary Pressure Curves for Analysis of Production Well Formation Damage
Authors: Donaldson E. C. 
Published: December 2007

ABSTRACT
Capillary pressure phenomena in the vicinity of the wellbore govern the rates of production of oil and water because the relative fluid saturations are functions of the capillary pressure existing between the fluid phases. Assuming that water is the wetting phase in contact with the porous system, which is generally true of fields that have been waterflooded, the imbibition capillary pressure curve applies since the water saturation at the well is gradually increasing. With water wetting the solid, the capillary pressure of the aqueous phase must be continuous within the porous system and into the well. Capillary pressure does not exist (is zero) at the exit face with the rock (the wellbore), therefore water cannot flow into the well until a condition of zero capillary pressure is obtained within the formation in the vicinity of the well. Hence, a newly drilled well initially produces only oil until the capillary pressure reduces to zero. Water is then produced in greater and greater quantities as the water saturation moves from the point of zero capillary pressure toward a residual oil saturation by imbibition. When imbibition ceases the imbibition capillary pressure curve becomes negative requiring input of greater energy for simultaneous production of oil and water, until finally the imbibition curve approaches a negatively infinite value and all production of oil stops as the residual oil saturation is attained.
The pore size distribution of the rock governs the capillary pressure behavior. A decrease of the pore size distribution produces a higher residual oil saturation and results in a decrease of the oil production rate that may be as much as 2–5 times less.
Factors adversely changing the pore size distribution, and hence the capillary pressure, at the production well are migration of fines, precipitation of crude oil components (paraffins and asphaltenes), and campaction of the sand due to pressure draw-down.
These aspects of adverse capillary phenomena at the wellbore are analyzed by capillary pressure measurements of cores having large and small pore sizes and by comparison to results with cores which are partially plugged with fines, bacteria, etc. The pore size distributions and capillary pressure are measured before and after plugging.
Liquid Extraction From Produced Gas on Small Oil Leases
Authors: Skinner D. R. 
Published: December 2007

ABSTRACT
"Micro" gas plants, small, refrigerated, liquid extraction plants that are capable of removing hydrocarbon liquids from small gas production streams normally associated with oil production operations are described and the processes involved are discussed. Operation and maintenance of these small units are described. Two examples are presented to illustrate application of the small units. Although not all lease operations can benefit from these units, small liquid extraction units can recover substantial volumes of propane, butane, and natural gasoline (often called liquifiable natural gases or LNG) from produced gas streams on many small oil leases.
Reservoir Geology of Some Tight Clinton Sandstones, Eastern Ohio
Authors: Knutson C. F. , Ammer J. R. , Yost A. B. 
Published: December 2007

ABSTRACT
In an effort to better understand the geologic and engineering factors that explain the production performance of the tight Clinton sandstone of Eastern Ohio, logs, completion data, and production performance records were evaluated for a number of Clinton sandstone wells in east central Ohio.
The wells were divided into low slope (linear) and high slope (radial) groups based on plots of log cumulative production versus log time. The distributions of expected recoveries from these two groups of wells were compared using the chi square and Pearson's P-M correlations, and were found to be significantly different. The linear wells had a median expected ultimate production of less than 20 MMcf (5.7 × 105 m3) while the radial group had a median of more than 50 MMcf (1.4 × 106 m3). Some of the wells tended to be located in contiguous trend areas. The distance to the drainage boundary was also calculated for the linear and radial wells. The median length for the linear wells is about 500 feet (150 m) while the median radius for the radial wells is about 2,000 feet (600 m).
The intent of this paper is to provide industry with a methodology that can be used to calculate reservoir parameters, such as size and geometry, which are important in designing stimulations and in estimating reserves.
Pressure Decline Analysis With the Christianovich and Zheltov and Penny-Shaped Geometry Model of Fracturing
Authors: Lee W. S. 
Published: December 2007

ABSTRACT
In 1979, Nolte1 pioneered an analysis of pressure decline after fracturing to gain information on fluid loss characteristics, fracture dimensions, fluid efficiency and fracture closure time. Since then, this method has received ever increasing attention in the petroleum industry. In the Nolte method, a fracturing job of short duration is performed on a formation, and pressure decline data are collected after shut-in before attempting a large-scale treatment. The information gained from the pressure decline analysis is utilized to design large-scale treatments to help achievebetter performance. This treatment of short duration is conventionally called a 'MINI-FRAC' job. This analysis by Nolte was initially limited to the Perkins and Kern model for fracture geometry. In Nolte's original work, two type curves were developed for analysis, one being used for treatments in which fluid efficiencies are low and the other for treatments in which fluid efficiencies are high.
In the present paper, Nolte's analysis has been extended to two other standard models, i.e. Christianovich-Zheltov and the Penny or radial model. An additional type curve has been developed which can be used for all three models. This type curve should replace one of the Nolte type curves used for high fluid efficiency.
The results of this analysis indicate that for minifrac treatments of short duration, it is advisable to first run a penny model analysis and compare results obtained from the Christianovich-Zheltov model and Perkins and Kern model because at earlier stages of growth the fracture may be penny-shaped. This model also indicates that Christianovich-Zheltov model is less sensitive to the estimate of gross fracture height than the Perkins and Kern model. The estimate of gross fracture height is rather difficult.
Single-Stage, Multiple-Zone Stimulation: An Effective Method of Stimulating the Niobrara Formation
Authors: Eason C. R. 
Published: December 2007

ABSTRACT
Recently developed fluid technology incorporated with a limited entry perforation design has proved to be an effective alternative in stimulating low-yield secondary reservoirs. Three benches within the Niobrara Formation have been identified as a secondary source of hydrocarbons in existing wells. Through a comprehensive study on core extracted from the Niobrara Formation, a precisely engineered technique of simultaneously stimulating the complete three zones or a combination of these three zones has been successfully implemented.
Further extrapolations from original design work include stimulation of the complete Niobrara and Codell Formations. Early evidence has suggested a design success. Evaluation of this most recent treatment is still in a data-acquiring mode. If proved valid, implications are suggesting a greater reduction in costs of stimulating these secondary reservoirs.
Presented within the following paper are associated problems of fluids and formation characteristics of the Niobrara Formation. Also included are production data for before and after the treatment. A representative job-design discussion of Niobrara and Niobrara-Codell Formations is outlined.
Prediction of Vertical Hydraulic Fracture Migration Using Compressional and Shear Wave Slowness
Authors: Newberry B. M. , Nelson R. F. , Ahmed U. 
Published: December 2007

Abstract
Documented field results of vertical hydraulic fracturing suggest that quite often the created fracture migrates vertically away from the formation of interest (the hydrocarbon-bearing zone), thereby producing undesirable results. The single set of information needed to help answer questions concerning fracture migration consists primarily of in-situ stress, tensile strength, and elastic constants of the rock material in and around the formation of interest.
This paper describes the use of full waveform data from a sonic wireline tool to determine the relative stress distribution and the resultant induced hydraulic fracture height. Compressional and shear wave slowness, derived from the sonic waveforms, are used to calculate the dynamic elastic rock properties. A transversely isotropic model is used to compute the in-situ stress from the elastic properties. Advantages of the use of wireline measured data are discussed, as are the limitations of the technique. Final evaluation of the technique is shown through the comparison of predicted and poststimulation measured vertical fracture height. Two field cases are presented to illustrate the technique.
Perforation Stability in Low-Permeability Gas Reservoirs
Authors: Chenevert M. E. , Thompson T. W. 
Published: December 2007

Abstract
A perforation into the side of a borehole sets up a very high stress environment which may lead to rock collapse around the perforations. This study shows that a formation which has a low permeability, and is abnormally pressured, should be permeability, and is abnormally pressured, should be produced with a very limited drawdown so as to prevent produced with a very limited drawdown so as to prevent perforation collapse. perforation collapse.
Proppant Settling in Non-Newtonian Fracturing Fluids
Authors: Roodhart L. P. 
Published: December 2007

ABSTRACT
Experimental results of the settling of spherical particles in flowing non-Newtonian fracturing fluids show that Stokes Law based on 'Power Law' viscosities is insufficient to predict particle fall rates in both flowing and quiescent fluids.
In a stagnant fluid the experimental settling velocities are more than an order of magnitude higher than those calculated, while in a flowing fluid, settling is lower than that calculated. These phenomena can be explained by extending the 'Power Law' model with a zero shear viscosity and by assuming an anisotropic viscosity in a flowing fluid.
Anisotropy in the viscosity only becomes important above shear rates of, say, 25 s-1, and so will not play a role in the majority of fracturing treatments where average shear rates in the fracture will be below this value.
Modern Maintenance Management in Mobil Producing Nigeria
Authors: Ogunlade O. A. , Peters Klaus E. 
Published: December 2007

ABSTRACT
This paper describes the process of reorganizing the maintenance function in a remote offshore oil producing operation from a breakdown repair system to a planned, structured system based on Planned Maintenance. Highlighted are the creation and operation of a maintenance planning department and the role of warehouse operation in a remote area. The function of data processing is discussed and an outlook towards future industry trends in respect to personal computers is given.
Appraisal of Steamflood Models
Authors: Abou-Kassem J. H. , Farouq Ali S. M. 
Published: December 2007

ABSTRACT
Eleven numerical steamflood models, developed by various investigators over 1969-1982, are analyzed for this evaluation. These models are sometimes similar in certain aspects and different in others. A comparative evaluation of existing numerical steamflood models contributes greatly to the state of the art, and helps in developing new ideals and detecting missing links that may not be realized otherwise.
This paper presents a general steamflood model. The assumptions and derivation of equations of various steamflood models are presented. Similarities and differences between models in the areas of mathematical models, treatment of nonlinearities, formulation methods, and methods of solution used are presented and discussed in detail.
The use of Reservoir Engineering in the Development of the Magnus Oil Reservoir
Authors: Atkinson J P 
Published: December 2007

ABSTRACT
The Magnus Field was discovered in 1974. Data sets from thirteen wells were used in extensive reservoir engineering studies to delineate the reservoir and formulate a development plan. Close examination of data from pressure build up tests, wireline logs, formation pressure sampling tools, and analyses of sampled fluids revealed variations in rock and fluid properties which could have indicated the presence of reservoir discontinuities and hence introduced uncertainty in the production forecasts. The fluids in the Magnus reservoir were initially at a much higher pressure than would be calculated due to hydrostatic gradient. This indicated that the oil accumulation could be isolated from surrounding aquifers and that water injection would be essential during production in order to maintain reservoir pressure and to sustain oil production rates. Test results on wells 211/12-2 and 211/12a-9 indicated that the permeability in the aquifer zone underlying the Magnus oil was an order of magnitude lower than that in the oil zone. Following examination of core material it was decided that direct injection of water into the aquifer zone was not practicable and that injection into the oil and residual oil zones would be necessary.
Seven of the Magnus wells, drilled from semi-submersibles, were suspended and subsequently tied back to the platform to give early oil production before production wells, drilled from the platform, became available.
This paper outlines the field data available prior to the start of production, and shows how reservoir engineering studies have used the early production history data to resolve uncertainties in the conceptual reservoir model and to optimise the future development well locations in order to maximise data acquisition, oil recovery and oil production potential.
Probabilistic Hydrocarbon Reserves Estimation: A Novel Monte Carlo Approach
Authors: Behrenbruch P , Turner G J , Backhouse A R 
Published: December 2007

ABSTRACT
Probabilistic reserves estimating using a generalised Monte Carlo approach has many advantages over simpler deterministic or other probabilistic methods. The particular method described deals more thoroughly with geologic structural dependency and at the same time allows for a high degree of accuracy. Data preparation is kept to a minimum, allowing seismic and other basic data to be used directly in calculations without the need of preparing time consuming area-depth graphs used in more conventional methods. A further advantage is the elimination of certain arbitrary decisions related to extreme structural scenarios based on geological mapping of a very limited number of possible situations. Sensitivities related to uncertainties and errors are handled in an easy m anner.
The approach related to gross rock volume calculations is different from more conventional probabilistic reserves simulations in that it involves the direct manipulation of all surfaces bounding the most likely rock volume. Such uncertainty, described by statistical distributions (e.g. seismic velocity error) and functional relationships, involves geological horizons bounding individual sands (reservoirs), structural surfaces such as unconformities and faults, and fluid contacts.
Drill Vessels Float in Aerated Water
Authors: Hammett D S 
Published: December 2007

ABSTRACT
Model tests, calculations, and case studies prove that a floating vessel will not sink due to gas reducing the water density in or adjacent to a subsea blowout. Several floating drill vessels have been lost as a result of subsea blowouts. Reports have circulated that the rig sank into something similar to a hole in the ocean caused by gas bubbles suspended in the water reducing its specific gravity. These erroneous reports, believed as truth by many people, have resulted in the modification of operations resulting in decreased safety.
Several subsea well control operations have caused accidents and losses because the riser was not disconnected. This action was taken in fear of sinking in aerated water. The losses occurred because the vessel winched itself off the drill site to get away from the subsea well before disconnecting. Due to the high riser/BOP angle, the riser could not be disconnected and well control was later lost and the gas/oil flowed directly to the rig floor where massive fire/explosion damage occurred.
If there had been a better understanding of water density, the rig personnel could have closed all hatches, shut-down all engines, disconnected the riser and released mooring lines at one end of the rig, and safely removed the rig out of the aerated water.
This paper presents some of the technical data and references available which prove that a floating vessel will not sink due to loss of water density.
Also presented in this paper is a concept which intentionally subjects a floating vessel to aerated water, to divert and control subsea blowouts. Several blowouts have occurred which have resulted in oil and/or gas flowing from a subsea well or BOP. When oil flows to the surface pollution occurs and it is impossible to control or collect pollution on the ocean surface. The concept reported in this paper diverts the subsea well pollutant flow to a collection vessel before the flow reaches the surface. A funnel with riser suspended from a barge is positioned over the subsea well. The well flow, which contains gas, lightens the fluid column inside the riser and the well fluids flow up through the riser to the collection barge. Once the well flow is diverted, a method of entering and stopping the well flow from the well bore is available via the funnel and riser. This complete system, the model tests, the field application, and the future use of the diverting and controlling procedures are reported in this paper.
Reliability Analysis of Alternative Gas Well Safety Valve Completions
Authors: Wilson P M , Okeke S O 
Published: December 2007

ABSTRACT
Using conventional reliability analysis techniques, a gas well completion was examined to determine the best subsurface safety valve installation for maximum well safety. Consideration was given to a well's production, wireline and workover activity, and use was made of reliability data based upon 3600 gaswell years of experience in the Netherlands and a worldwide survey of offshore blowouts.
A deep set (packer depth), surface controlled subsurface safety valve completion was found to be the most reliable completion, whilst wireline activity posed the dominant risk in well safety.
Development of a Deepset Electric Solenoid Subsurface Safety Valve System
Authors: Gresham J S , Turcich T A 
Published: December 2007

ABSTRACT
This paper reviews the project to develop a wireline retrievable, surface controlled, subsurface safety valve system capable of being set at great depth.
Following alternative system reviews, four valves were selected for further evaluation and possible development. Only one of them, the electric solenoid safety valve system, has been fully developed and field proven.
In addition to the development of the electric solenoid safety valve and its respective nipple, the special cable that was developed for the system, the high pressure wellhead pack-off arrangement for cable passage through the wellhead and the electric safety valve control system are discussed.
The field experience with this safety valve, in two gas well completions, the wider application in Shell's operations and possible future developments are described.