bluuebunny/crossref_metadata_2025_split huggingface dataset:
Producing The Well In Artificial Lift By a Subsurface Compensated Pump: A New Production Method
Authors: Buchman Smil S. 
Published: December 2007

Introduction
This paper presents a new production method in which the reservoir energy spent to lift the production from perforation-depth to the dynamic liquid level is replaced by surface energy, and consequently the well daily rate and cumulative production is increased by 200 - 250 %. The method can be used in any well at any time.
The paper is based on the analysis of how the reservoir energy generated by the expansion of the reservoir fluids is used to produce the well:
PROFITABLE USAGE: Moves the production through the pay zone into the well bore.
WASTEFUL USAGE: Sends the reservoir energy to:Overcome the liquid friction along the production flow path.Lift the production from perforation-depth to the dynamic liquid level.
Present production practice recognizes and reduces only the reservoir energy wasted to overcome the liquid friction through the pay zone by using better and cleaner perforations, acidizing, fracturing, and other techniques. When less reservoir energy is used to overcome the frictions through the pay zone, the well performance, in both rate and cumulative production, is increased.
To date all artificial lifting methods are spending surface energy only to lift the production from the dynamic liquid level to the surface. However, the energy needed to lift the production from perforation-depth to the dynamic liquid level, the largest waste of reservoir energy, is now overlooked and has not been recognized as the most important way to significantly increase well performance. The proposed new production method substitutes the reservoir energy by surface energy in order to lift the production from perforation-depth to the dynamic liquid level. Accordingly the well performance in day rate and cumulative production is increased by 200 - 250 % compared to the actual well performance.
The quickest and easiest way to produce the well according to the new production method, is to run a subsurface compensated plunger pump assembled from the API Spec-11AX parts, and work with the same beam pump. A subsurface compensated pump, is a liquid lifting device, which can not be drawn by the well pressure.
How to Maintain High Producing Efficiency in Sucker Rod Lift Operations
Authors: McCoy J. N. , Rowlan O. L. , Becker D. J. , Podio A. L. 
Published: December 2007

Abstract
Throughout the world the most commonly used method to artificially produce wells is by sucker rod lift. Low producing efficiency caused by incomplete pump fillage is the most common operational problem experienced by sucker rod lifted wells. Incomplete pump fillage is the result of having a pump capacity that exceeds the production rate of the well or having poor gas separation at the pump intake with a portion of the pump displacement being lost to gas interference. More efficient operations and lower cost will result, if these wells are operated with the pump filled with liquid by eliminating any gas interference in the pump and controlling pump run time so the pump displacement will match the inflow of liquid from the reservoir into the wellbore. The operator must monitor well to insure that the pump has no mechanical problems and efficient operations are maintained as all the available liquid is produced from the wellbore.
Advances in Horizontal-Oriented Perforating Optimize Perforation Efficiency and Production While Maintaining Borehole Stability
Authors: Benavides Simon P. , Myers William D. , Van Sickle Edgar W. , Vargervik Kristian 
Published: December 2007

Abstract
A major operator in the North Sea put one of their fields on stream in the autumn of 1988. Since then, over 1.7 billion barrels of oil have been produced, reaching a peak of more than 500,000 BOPD. Today, an estimated 0.9 billion barrels of oil remain to be recovered from the field; however, production has fallen to less than 400,000 BOPD and the operator is facing tremendous challenges to increase production.
New technologies, such as horizontal drilling and horizontal oriented perforating have helped increase production. Drilling in a water depth of 109 m of water, the operator wanted to optimize production from a 2246-m horizontal well section by reducing the risk of future sand production and selecting the most effective perforation coverage.
Perforating in highly deviated or horizontal wells presents any service company with a serious technical challenge. Attempting to maintain wellbore and perforation tunnel stability by perforating in the direction of maximum stress compounds the complexity of the perforating job. Ensuring that orientation remains valid while navigating through severe doglegs requires detailed pre-job design planning supported by applicable research data.
This paper discusses advances in horizontal oriented perforating in long horizontal sections designed to optimize perforation efficiency and production. The techniques and results discussed are applicable to any horizontal or highly deviated well where orientation of charges to maintain wellbore stability is critical. New developments to navigate through severe doglegs and maintain orientation are significant contributions to perforation technology. Some of the results and experiences encountered while performing an oriented perforating job in a 2246-m horizontal section of the North Sea well are also discussed in this paper. A world record was set by perforating a net of 1496 m of the horizontal section in a single trip with orientation successfully verified. Additional discussion on the testing and research that preceded the job is presented.
As demonstrated in positive results from the North Sea well, perforating with oriented charges in horizontal sections will play a key role in the future to assist operators increase and optimize production from new or declining fields.
Characterization of Slug Flow in Horizontal and Inclined Pipes
Authors: Bagci S. , Al-Shareef A. 
Published: December 2007

ABSTRACT
Two-phase flow in horizontal and inclined pipelines can cause significant practical operating problems. When slugs flow in a horizontal pipeline that contains sections of different inclinations they undergo a change of length and slug flow characteristics as the slug move from section to section. In addition, slugs can be generated at low elbows, dissipate at top elbows and shrink or grow in length as they travel along the pipe.
A mathematical model and a computer program were developed to simulate these phenomena. The model was based on the sink/source concept at the pipeline connections. A connection between two pipeline sections of different slopes was conveniently called elbow. An elbow accumulates liquid as a sink, and releases liquid as a source. The sink/source has a characteristic capacity of its own. This capacity is positive if the liquid can indeed be accumulated at the elbow or negative if the liquid is actually drained away from the elbow. This type of treatment effectively isolates the flow upstream from an elbow from that downstream, while still allowing flow interactions between two detailed pipeline sections. The hydrodynamic flow model was also used to calculate the film liquid holdup in horizontal and inclined pipelines. The model can successfully predict the liquid film holdup if the liquid film height is assumed to be uniform through the gas pocket. Many other models were used to calculate all the needed parameters to perform the sink/source model.
The overall effect of horizontal and inclined pipelines on slug flow depends on the operating flow rates and pipeline configurations. For special case of near constant slug frequency corresponding to moderately high superficial liquid and gas velocities, this effect was found to be small. The changes in the film characteristics between two adjacent pipeline sections were found to be mostly responsible for the pseudo-slug generation, slug growth and dissipation in the downstream pipeline sections. The film liquid holdup decreased with increasing pipe diameter. The unit slug length increased at the upstream inclined pipes and decreased at the downstream inclined pipes with increasing pipe diameter. The possibility of pseudo-slug generation was increased at large pipe diameters even at high sink capacities. At low sink capacities, no pseudo-slugs were generated at high superficial velocities. The slug flow characteristics were more affected by low superficial gas and liquid velocities, large pipe diameters and shallow pipeline inclinations.
Enhanced Fracture Stimulation in the Deep Morrow Sandstone in Western Oklahoma
Authors: Ely John W. , Martin Michael A. , Duenas Jose J. , Trythall Jerry R. 
Published: December 2007

Abstract
Late in the fall of 2000 a concerted effort was initiated to optimize fracture stimulation of the Deep Morrow Sandstone in Mayfield area of Western Oklahoma. The producing horizons, typically four or more stacked pays, in the Mayfield area are from 17,000 to 20,500 feet and exhibit extreme heterogeneity including tremendous variations in permeability, pressure, and aerial extent of the reservoir. The presence of severe depletion in some of the zones greatly complicates completion techniques.
The initial approach was to utilize pressure data from previous treatments in the field and attempt to gain qualitative values for stress profiles. Based upon this data available a procedure was developed to optimize stimulation treatments using an iterative process. The use of pre-job FET's allowed evaluation of fluid efficiency and also to identify severe tortuosity problems.
The use of field proven techniques used in other deep high temperature reservoirs allowed for removal of severe near-wellbore problems allowing for placement of up to 7 pound per gallon bauxite in wells below 20,000 feet. The authors will elucidate the step-by-step procedures utilized in selection of pad volume, leak-off control methods, and specific procedures for removal of tortuosity. Additionally we will discuss the success and failures of zonal isolation techniques and the successful use of pseudo-limited entry on some of the producing horizons.
The new procedure allowed for successful placement of higher concentration of proppant and much larger volumes of proppant.
A major part of the paper will be comparing the newgeneration treatment results to offset operators and comparison of production data on a well-to-well basis.
Use of After Closure Analysis to Improve Hydraulic Fracturing Designs, Application on Algeria's In-Adaoui gas Field.
Authors: Benelkadi S. , Belhaouas R. , Sahar M. 
Published: December 2007

Abstract
Hydraulic fracturing design is highly dependent on the knowledge of the injection fluid efficiency. This parameter is generally derived from the interpretation of the calibration tests fall offs. Two popular methods are the square root of time and Nolte's G function1,2,3,4. Such interpretations are not always straightforward and can lead in some practical applications to the failure of propant placement i.e: a screen out with an impact on the post frac well's productivity.
In this paper a new interpretation technique for closure pressure determination is presented. It is based on a novel utilisation of Nolte's F function5. Field cases on Algeria's In-Adaoui field are analysed. Proppant placement failures are explained. These examples demonstrate the usefulness of the F function for improving hydraulic fracturing design whether for a conventional permeabilty estimation or for closure pressure and hence efficiency determination.
Selection of Foam Flushes and Foamed Cement Proves Effective for Remedial Operations of Low-Pressured Formations—Case Histories
Authors: Millard Matt , Getzlaf Don , Griffith James E. 
Published: December 2007

Abstract
Remedial cementing operations and zone abandonment are difficult to accomplish when low-pressure formations possess high feed rates at low, or even vacuum, surface pressures. Such is the case with several heavy-oil wells recently abandoned in Western Canada. These wells and their respective formations average an economic life of approximately ten years, during which a large amount of formation sand is produced. Traditionally, whenever exposed to hydrostatic pressure, these zones exhibit a vacuum at very large feedrates. Scorecard results of conventional cement squeezes required an average of 2.6 attempts to obtain a positive squeeze pressure. Many conventional cementing abandonment attempts were unsuccessful, resulting in the placement of a casing patch across the open perforations. The mechanical seal was effective in sealing the wellbore, which allowed exploitation of deeper zones. However, this seal reduced the casing internal diameter and can limit further production operations. Also, this mechanical seal may not serve as a final abandonment under certain government regulations.
The solution to this challenge was developed by tailoring a treatment pumping schedule that incorporates the use of foamed nonreactive, reactive spacers and foamed cement blends. This new treatment design was used on several wells in early 2002. On most of the wells, positive squeeze pressure was obtained on the first attempt and saved approximately CAD $15,000 per well. The improved process is now being planned for two adjacent fields. This paper details the well challenges and results found by a Canadian operator to successfully abandon low-pressure, heavy-oil producing zones. The solution developed for the case history wells is also presented.
Buckling of Tubulars Inside Wellbores: A Review on Recent Theoretical and Experimental Works
Authors: Cunha J. C. 
Published: December 2007

Abstract
Buckling behavior of tubulars inside wellbores is the major subject of many articles. This paper presents a general overview on most of the material available in the literature on the subject and also comments on the different, and sometimes conflicting solutions presented in various works.
Different aspects of the phenomenon are discussed including sinusoidal (lateral) and helical buckling and influence of torque.
Experimental and Simulation Studies of Sequestration of Supercritical Carbon Dioxide in Depleted Gas Reservoirs
Authors: Seo J. G. , Mamora D. D. 
Published: December 2007

Abstract
This paper presents experimental and simulation studies to evaluate the feasibility of sequestering supercritical CO2 in depleted gas reservoirs. Experimental results were simulated to obtain gas-liquid relative permeability curves used in the field simulation study.
A 3D simulation model of one eighth of a 5-spot pattern was constructed to evaluate injection of supercritical CO2 under typical field conditions. Simulation results indicate the following. First, a large amount of CO2 in sequestered: about 1.2 million tons in 29 years (40-acre pattern), and 4.8 million tons in 56 years (80-acre pattern). Second, a significant amount of natural gas is also produced: about 1.3 BSCF or 74% OGIP (40-acre pattern), and 4.9 BSCF or 68% OGIP (80-acre pattern). Third, at $2.00/MSCF, produced gas revenue amounts to about $2.6 million to $9.8 million, which could help defray the cost of CO2 sequestration. In short, CO2 sequestration in depleted gas reservoirs appears to be a win-win technology.
Oklahoma's New Guardian Program Guidance for the Assessment and Cleanup of Complex Crude Oil and Condensate Spills
Authors: Billingsley Patricia 
Published: December 2007

Abstract
Pollution Abatement Division staff have been working with oil industry representatives, the American Petroleum Institute (API), and Risk Based Corrective Action (RBCA) experts to thoroughly revise our guidance for complex spills and discovered historic pollution. While the focus is on crude and condensate from production sites, pipelines, and tank farms, cleanup of refined hydrocarbons is also briefly discussed. There are seven steps from assessment through cleanup or stabilization to closure. A new TPH analytical method, similar to Texas method 1005 pushed to C35 but with 4 reporting ranges, is being developed by the Oklahoma State Department of Environmental Quality. There is also a revised brochure for reporting and responding to spills, which has guidance for immediate and short term response actions.
In this new system, operators can choose to follow the revised category/risk factor pathway, which has fixed numerical cleanup criteria; or can prove stabilization, with monitored natural attenuation for the "cleanup"; or can instead use a RBCA approach. The PERF group did a fractionation analyses of numerous crude oils and condensates from both Oklahoma and worldwide to determine their levels of potentially harmful compounds. The numerical category cleanup criteria and a new RBCA Tier 1 lookup table contain risk-related cleanup levels based on these analyses, as well as oil mobility limits in soils and the effects of crude and condensate in the root zone on plants. The guidance also specifies the software to be used (developed for Oklahoma by API) if a company decides to do a site specific Tier 2 or 3 RBCA.
Oklahoma Centennial Commemorative Medallion Design by Betty Price, Executive Director, Oklahoma Arts Council.
The Mitigation of International Security Risk
Authors: Keable Kevin BP , Hitchcock Mike 
Published: December 2007

Abstract
As the oil and gas industry becomes more and more reliant on developing fields in third world and developing countries, they must also embrace the fact that whilst the rewards are certainly higher, so are the risks. Simply put, everything comes at a price. Terrorism, the threat of physical attack, fraud and corruption are of great concern to those responsible for investing in and sending staff to the higher risk regions of the world. But our industry has in certain areas been too blasé about the security risks in many countries and is guilty of reacting to problems rather than proactively reducing the risk to staff and assets. This paper outlines some of the background to the particular challenges faced by the oil and gas industry and solutions to the ever present security puzzle.
Determination of Drilling Mud Density Change with Pressure and Temperature Made Simple and Accurate by ANN
Authors: Osman E. A. , Aggour M. A. 
Published: December 2007

Abstract
An artificial neural networks (ANN) model has been developed to provide accurate predictions of mud density as a function of mud type, pressure and temperature. Available experimental measurements of water-base and oil-base drilling fluids at pressures ranging from 0 to 1400 psi and temperatures up to 400 °F were used to develop and test the ANN model. With the knowledge of the drilling mud type (water-base, or oil-base) and its density at standard conditions (0 psi and 70 °F) the developed model provides predictions of the density at any temperature and pressure (within the ranges studied) with an average absolute percent error of 0.367, a root mean squared error of 0.0056 and a correlation coefficient of 0.9998.
North Kuwait Down-hole Corrosion Management Challenge and the Use of New Corrosion Detection Tools to Define the Extent of the Problem
Authors: Al-Ajmi Moudi Fahad , Attid Juma K. , Daye Alex 
Published: December 2007

Abstract
The North Kuwait (NK) Development Plan calls for rapid increase in NK production, mainly through the implementation of waterflooding in NK major reservoirs. The new production profile incorporates increased water production and, based on corrosion prediction models, results in elevated corrosion rates in down-hole completion equipment. This predicted increased corrosion has already become a reality in the past three years. Severe down-hole corrosion in production and injection wells has resulted in tubing and casing failures and severe casing/tubing corrosions. Remediation of these wells has resulted in problematic, high cost workovers, and in one case, the loss of the productive interval and the associated reserves.
To manage current and future corrosion in NK, an extensive corrosion-monitoring program has been implemented to initially identify the extent of corrosion in the current well stock and then to adopt corrosion prevention strategies to mitigate the problem and reduce the associated cost and production impact. The down-hole internal corrosion monitoring effort is one of the first steps in implementing the NK Corrosion Management Plan.
This paper discusses the results of the program to date and describes the diagnostic tools used to effectively monitor the extent of down-hole corrosion in North Kuwait. Different tools such as the caliper, MicroVertiLog tool (MVRT), and surface inspection methods have been utilized to quantify down-hole corrosion. The paper also compares MVRT tool response with caliper and surface inspection data in an effort to ensure down-hole corrosion detection corresponds with results measured at surface. This will allow immediate corrective action to be taken for the completions based on down-hole log results.
Improving the Production of Heavy Emulsion Crudes in the Bahrain Field: Experimental and Field Investigations
Authors: Al-Bastaki N. , Abbas A. , Zubari H. 
Published: December 2007

Abstract
In crude oil production, the generation of heavy oil/water emulsions can result in a significant drop in the production rate due to the high viscosities of the emulsions. The strong agitation and mixing that takes place at the inlet of the well bore together with the presence of the naturally existing emulsifying agents in the crude contribute to the formation of the emulsion. A number of methods can be used to mitigate this problem such as the injection of surfactants into the formation and surface treatment. The objective of this paper is two-folds. Firstly, the results of an experimental program carried out to evaluate the efficiency of several surfactants to demulsify crude oil / water emulsions are presented. Secondly, a novel cost effective technique for injecting the surfactant into the well utilising existing gas lift facilities at the well heads is described together with a number of other techniques which have been tested for treatment of emulsions.
The experimental study was performed on crude oil/water emulsion samples obtained from two sandstone reservoirs in the Bahrain field. The measurements included effects of surfactants on the degree of demulsification, surface tension and shear viscosity. An optimum surfactant/emulsion volume ratio of around 1.5 to 2% was noticed in most cases for the specific wells investigated. The addition of surfactants considerably reduced the shear viscosity and surface tension of the emulsion. As expected the surface interfacial tensions decreased with increasing temperature.