bluuebunny/crossref_metadata_2025_split huggingface dataset:
Utilizing Statistical Process Control Tools to Test Free Cycle Plunger's Potential on Tight Gas Wells
Authors: McWilliams Jay Paul 
Published: December 2007

Abstract
The free cycle plunger is a relatively new means of removing wellbore fluids. As gas reservoir pressures are depleted and production rates decline, liquid loading becomes a greater problem. When flow rates fall below minimum lift, liquid accumulates in the wellbore, causing additional backpressure on the formation, which reduces production rates.
A free cycle plunger is designed to increase daily plunger cycles as compared to a conventional plunger lift system. This increase reduces the slug size, requiring less energy to lift the plunger to the surface. The plunger design allows it to fall while the well is flowing, permitting more daily flow time and increased natural gas production. Recently, several types of one-piece and two-piece free cycle plungers have been introduced to the market.
This paper discusses the results of a 45-well pilot of the free cycle plunger in the San Juan Basin. The pilot's objective was two-fold: to test the hypothesis that installing the free cycle plunger would reduce slug sizes, increase daily flowing time, and increase overall production and to establish better criteria for future installations. To accomplish the second objective, it was necessary to analyze the positive and negative responses to the free cycle plunger and determine the factors that led to each response. The data was then analyzed [CP1]using statistical modeling tools to determine the most important factors affecting the response variable increased production (uplift). This paper will discuss the results of a regression model and response surface methodology (RSM) analysis. The regression model was built to determine the significance of several factors and to predict the production response from installing the system. The response surface methodology analysis was used to determine the best candidates for the installation of the system.
The concepts of Statistical Process Control (SPC), the application of statistical techniques to control a process1, were used to implement and evaluate the pilot. To most efficiently and accurately test new artificial lift technologies, it is essential to implement a controlled test of the technology and to use proper statistical methods to evaluate the results.
Optimization of Horizontal Well Completion Design
Authors: Furui K. , Zhu D. , Hill A. D. , Davis E. R. , Buck B. R. 
Published: December 2007

Abstract
A well completion is a critical interface between the productive formation and the wellbore. An effective completion must maintain mechanical integrity of the borehole without creating any significant restrictions in the flow capacity of the well. In this paper, we outline a process to design optimal completions for horizontal wells by applying comprehensive skin factor models that include damage and turbulence effects for all common types of completions.
Slotted or perforated liner, cased and perforated completions, or gravel pack completions have been used in horizontal wells for borehole stability and sand control purposes. However, these completions may have lower productivity (as characterized by a positive skin) relative to an equivalent openhole completion because the convergent flow to perforations or slots increases fluid velocity in the near-well vicinity. In addition, any reduced permeability zones (formation damage caused by drilling, completion, or other processes) magnify the convergent flow effects, and hence, may result in severe skin factors. Compound effects of formation damage around the well completion, a crushed zone due to perforating, the plugging of slots, and turbulent flow, as well as interactions among these effects are included in the model.
We first illustrate how to use the skin factor models to screen the available completion types for different applications. This screening approach considers reservoir permeability, permeability anisotropy, fluid properties, formation damage effects, and rock mechanical characteristics as the key parameters. The types of completions that yield the most productive well performance for this matrix of properties are presented.
A more detailed completion design is then illustrated by showing the use of the skin factor models for selection of liner completions for viscous oil reservoirs on the North Slope of Alaska. Application of the slotted or perforated liner models to the readily available liners showed that the completion skin factor can vary by as much as 40%, depending on the detailed characteristics of the slots or perforations in the liner (slot or perforation size, density, and distribution). This showed how analyzing the performance of the completion design can greatly increase well productivity at little or no cost.
Productivity of Selectively Perforated Horizontal Wells
Authors: Yildiz Turhan 
Published: December 2007

AbstractThis paper investigates the effect of selective perforating on horizontal well performance. Theoretical investigation is based on a general 3D analytical IPR model that was published previously. For a given perforation design, the changes in flow rate, pseudo-steady state productivity, and cumulative production can be computed using the solution. The investigation shows that the ratio of total perforated length to the drilled well length is the most dominant parameter controlling the long term performance of the selectively perforated horizontal wells. The other important parameters are the degree of formation and perforating damage.We additionally examined the effect of the so-called oriented perforating on the horizontal well performance in isotropic and anisotropic formations. Our research shows that accurately oriented perforating could significantly improve the well productivity in anisotropic formations.
Experimental Investigation of Various Methods of Tertiary Gas Injection
Authors: Kulkarni M. M. , Rao D. N. 
Published: December 2007

Abstract
Water alternating gas (WAG) injection is widely practiced for improved light oil recoveries. In this experimental study, we compare the WAG process against the continuous gas injection (CGI) process by conducting tertiary mode miscible and immiscible corefloods.
Inferences resulting from performance evaluations using ‘conventional’ tertiary recovery plots were found inappropriate. Therefore, a new parameter ‘Tertiary Recovery Factor’ (the oil recovery per unit volume of gas injected) was defined, and used in conjunction with the CO2 utilization factor, for the evaluation of tertiary coreflood recoveries. The definition of TRF not only helped to demonstrate experimentally that miscibility development has a positive effect on oil recovery, but also showed that the WAG mode of injection is better than Continuous Gas Injection (CGI) when overall performances are considered. The WAG floods demonstrated continual increase in the TRF throughout the life of the flood, however, for CGI miscible flood, TRF crested at about 0.6 PV injection and later declined with increasing gas injection. These plots demonstrate that the WAG process has better CO2 utilization efficiency compared to CGI. These results indicate that optimum performance could be obtained by a combination of CGI and WAG modes of gas injection. This paper provides conceptual analysis and experimental demonstration of WAG, CGI and their combination at reservoir conditions.
Reservoir Description and Numerical Simulation of Neocomian Gas-Condensate and Oil Reservoirs, Western Siberian Basin, Russia
Authors: Jenkins C. D. , Richmond P. L. , Wolcott D. S. 
Published: December 2007

Abstract
Integrated studies were recently completed for two gas-condensate fields with associated oil rims in the Western Siberian Basin of Russia. The two fields contain almost 500 billion cubic meters of gas and 700 million cubic meters of oil in large, low relief structures. The studies used seismic, core, log, fluid property and well test data from 118 wells to conduct petrophysical analyses, build geocellular models and conduct reservoir simulation. The reservoir description work identified controls on fluid flow, captured these in the geocellular models, and estimated hydrocarbons-in-place. After upscaling, full-field and mechanistic compositional models were constructed to investigate depletion strategies including volumetric depletion and improved recovery via lean gas injection. The results showed that high-graded well locations, zone commingling, hydraulic fracture treatments, horizontal drilling, and compression installation will be required to optimize development.
Flow Properties of Alaskan Heavy-Oil Emulsions
Authors: Singh Probjot , Thomason William H. , Gharfeh Samir , Nathanson Louis D. , Blumer David J. 
Published: December 2007

Abstract
Technical investigation to economically produce heavy oil in Alaska began in the 1980's. Since then a significant progress has been made in the production technology (multilateral drilling, artificial lift such as Electrical Submersible Pumps (ESP) and hydrolift Jet Pumps, etc.) to facilitate the production of the heavy oil. Still, a major challenge in the heavy oil production in the Alaskan arctic region is the formation of strong emulsions. The viscosity of these stable emulsions can be 2-3 orders of magnitude higher than the dry oil viscosity at the low ambient temperatures. The viscosities of these emulsions in the surface facilities are needed to predict the hydraulics in the fluid handling systems. Oil wet solid fines tend to further stabilize the emulsion and lower the separation efficiency. The stability of the emulsion can be gauged from the fact that oil external emulsion exists even up to 90% brine fraction and has the consistency of the peanut butter (highly viscous &gt;2x104 cP at room temperature). Laboratory titration experiments with alkanes indicate that the asphaltenes are stable in the crude oil. A Haake RS150 rheometer and a Brookfield DV-III viscometer were used to measure the viscosity of the live and dead emulsions containing various brine fractions at different temperature. The viscosity estimation by matching the pressure drop data from the field pipeline correlated well with the laboratory results. The viscosity of the emulsion decreases with temperature as predicted by the Arrhenius law. Heating the emulsion above 60°C causes partial destabilization of the emulsion resulting in slight deviation from the Arrhenius predictions. Emulsion breakers were found to be effective in reducing the viscosity of the emulsion even though they did not cause any physical separation of the brine. Based on these results, viscosity correlations have been developed to predict the viscosity of both live and dead oil-brine emulsions as a function of brine fraction, temperature, and shear rate. Viscosity correlations for emulsions presented by Barnea and Mizrahi showed excellent fit to the measured data. It was proposed to incorporate these correlations in the Pipesim, steady-state multiphase flow simulator for oil and gas production.
Material Balance Reservoir Model for CO2 Sequestration in Depleted Gas Reservoirs
Authors: Lawal Akanni S. , Frailey Scott M. 
Published: December 2007

Abstract
A depleted gas and gas condensate reservoir can store significantly more gas than a depleted oil reservoir with identical HCPV due to the fact that gas is more compressible than oil and the ultimate gas recovery in reservoir is typically higher than that of oil reservoirs. Also geologic CO2 storage in retrograde gas reservoirs can re-vaporize condensates and thus re-pressurized the reservoir which consequently leads to greater liquid condensate recovery.
A material balance equation for CO2 sequestration in gas reservoirs was developed to predict CO2 sequestration volume and survey CO2 sequestration operations during injection. Implications of dry, wet, and retrograde gas reservoirs on the P/Z plot usage are presented.
Practical Considerations for Pressure-Rate Deconvolution of Well Test Data
Authors: Levitan Michael M. , Crawford Gary E. , Hardwick Andrew 
Published: December 2007

Abstract
Pressure-rate deconvolution provides equivalent representation of variable-rate well test data in the form of characteristic constant rate drawdown system response. Deconvolution allows one to develop additional insights into pressure transient behavior and extract more information from well test data than is possible by using conventional analysis methods. In some cases it is possible to interpret the same test data in terms of larger radius of investigation.
There are a number of specific issues one has to be aware when using pressure-rate deconvolution. In this paper, we identify and discuss these issues, and provide practical considerations and recommendations on how to produce correct deconvolution results. We also demonstrate reliable use of deconvolution on a number of real test examples.
Managing the Tradeoffs: Similarities Between Managing New Product Development and Managing a Well Drilling/Completion Project
Authors: Shaw B. S. , Morris T. G. 
Published: December 2007

Abstract
To move and take action as quickly as possible, a development team must have a clear path and direction. It needs the best tools for the job and the ability to use them effectively. And it needs positive motivation to finish the work on schedule while achieving acceptable performance and quality goals. One of the potential "chokes" to the speedy delivery of both new products and new oil/gas wells is the decision-making process – the on-going debate between various interested and influential parties within the organization as to which aspects of the end product are most important. Multiple or conflicting priorities are often overlooked by planning teams when developing project schedules, budgets, performance objectives, and milestones. This frequently causes frustration, delays, and disappointments during and after the execution of the project.
The authors draw on their own experience in new product development (downhole tools) and subsea well delivery. The roles and responsibilities of a cross-functional new product development team are similar to those of an operator's on-shore support and offshore operations teams. For both types of development project, risk mitigation and project execution are best achieved by utilizing the skills and experience of a highly competent multi-disciplinary team using a well-planned and documented decision-making process. These teams benefit by inclusion of key supplier technical experts as full- or part-time contributing members. The ability of the project execution team to consistently make value-added decisions rapidly, under pressure, is a key element of their success. Specific examples from a supplier's new product development process and from a recent major deepwater development project are used to illustrate the key concepts.
Compact In-line Separation Project
Authors: Okimoto Fred T. , Klaver Theo , Verschoof Karel , Stanbridge David 
Published: December 2007

Abstract
Shell Global Solutions International (SGSI), CDS Engineering and Petroleum Development Oman LLC (PDO) are jointly field testing a new gas/oil/water in-line separation system (ILS) as part of the Smart Facilities Solutions portfolio of technologies. PDO has a requirement to have water injection facilities at the Al Huwaisah South West production site for reservoir support. Since start of production in 1971, the water cut has gradually increased to 85 – 90 % and is expected to increase further. This paper will describe the joint effort of Smart Facilities Solutions and CDS in applying new in-line separator equipment: a degasser, dewaterer, and hydrocyclone.
The Al Huwaisah field has been producing since 1971 with current gross production about 45,000 m3/d (see Figure 1). To improve oil recovery water injection (as well as infill drilling and exploitation of undeveloped areas) new facilities are planned. The project is to develop the South West Area by installing a facility to treat the SW production fluid to provide injection quality water for the water injection wells in the SW area. Presently, the SW area has only wells with a Multi-port Selector Valve (MSV) feeding a 12 inch GRE line to Al Huwaisah gathering station. Over the years the water cut has gradually increased to 85+% and is expected to increase further. The facilities will separate water, oil and gas. The compact inline separation system is designed to separate water, oil and gas. The ILS system is described in the next section. Water is locally injected. Gas and oil and any excess water is combined and sent to the central gathering station through an existing 12 inch GRE pipeline with gas and crude exported to Yibal. The compact inline separation system is a joint effort of SGSI and CDS.
The ILS was seen as an important technology, so SGSI went out into the market for competitive tendering based on the specific criterias of the ILS. CDS Engineering was selected as most suitable for the requirements needed for Al Huwaisah SW project.
Maximizing Fracture Conductivity with Proppant Partial Monolayers: Theoretical Curiosity or Highly Productive Reality?
Authors: Brannon Harold D. , Malone Mark R. , Rickards Allan R. , Wood William D. , Edgeman J. Randall , Bryant Josh L. 
Published: December 2007

Abstract
Hydraulic fracturing practitioners have long theorized that maximized fracture conductivity could be achieved by creation of fractures with partial monolayers of proppant. Fracturing mechanics and design experts have lamented that fractures filled with partial monolayers of proppant, while highly desirable, were "virtually impossible to achieve". The expert's reasoning was expressed as due to the inability to obtain uniform and complete coverage of the fracture with a partial monolayer, insufficient proppant strength to support the load, loss of fracture width due to proppant embedment and, potentially deleterious non-Darcy flow effects in the relatively narrow propped fracture. Many innovative fracturing products and design techniques have recently been developed and introduced to cost efficiently enhance well productivity. Evaluation of case histories of several wells recently treated utilizing some of these innovations have led to the consideration that perhaps the experts were a bit too hasty.
Slickwater fracturing has enjoyed a recent renaissance, in large part, due to the favorable treatment cost economics for the well stimulation benefit achieved using such non-damaging, low viscosity fluids. Slickwater fracturing treatments have historically been typified by pumping large volumes of slickened water at high rate to deploy relatively small volumes of frac sand. A potential shortcoming of slickwater fracturing treatments is the tendency for fracture propagation out of zone due to the high treating rates and, proppant settling below the target zone due to the poor transport properties afforded by the low viscosity treating fluid. Optimization of slickwater fracturing treatments employing recently developed ultra-lightweight proppants to facilitate proppant placement throughout the entire created fracture area has found success. Wells treated with the new proppants using refined placement techniques have been observed to experience extraordinary stimulation increases which are indicative of production through a partial monolayer proppant pack. The observed increases are resulting in payouts in a few weeks or months compared to the years experienced historically with previous methods.
The focus of this effort will be a review of case histories of wells treated with new products and placement techniques. Discussion of slickwater treatment design optimization and laboratory evaluation of the ultra-lightweight proppant partial monolayer conductivity and transportability is also provided. Results demonstrate how merging new technologies with old techniques can produce modern, high value results.
A Case History Of Optimizing Casing-Conveyed Perforating and Completion Systems in Tight Gas Reservoirs, Kenai Gas Field, Alaska
Authors: Garner J. Jay , Thompson Jim , Mack David J. , Devine Carolyn 
Published: December 2007

Abstract
Nine (9) wells have been successfully drilled, cemented and fracture stimulated in the tight gas sands of four (4) separate fields on the Kenai Peninsula, Alaska utilizing an industry unique Casing-Conveyed Perforating System (CCPS). For this nine (9) well program, 124 CCPS modules have been run, cemented in place, detonated and fracture stimulated. Of the nine (9) wells the initial five (5) wells were stimulated with an oil-based fluid while the most recent four (4) have utilized a water-based system. While the project has been an overall success, the drilling and completion team continues to utilize new and innovative technologies to optimize well performance and economics.
The normally-pressured middle and lower Beluga sands in the Kenai Gas (KG) and Beaver Creek (BC) areas exhibit significant vertical sections frequently exceeding 1,700 ft. The vertical pay quality is quite variable and consists of stacked fluvial sandstones 5 ft to 30 ft thick. The mineralogical composition of the sands is complex including a high percentage of quartz, clays, volcanics, coals, and fines with permeability ranging from 0.01 to 3 millidarcies. The sandstone packages are bounded by discontinuous shale, siltstone, and coal beds and present a challenging fracture stimulation environment. Produced gas is lean with a specific gravity of 0.56 with no condensate.
As mentioned above one of the most robust changes to the project has been a shift from a crosslinked oil-based (diesel) fracturing fluid to a "new-generation" aqueous based guar-borate system. This step change was made at the conclusion of extensive laboratory studies on core sections and has provided significant improvement with HSE, completion operations, well performance and ROI.
This case history paper reviews the revolutionary casing-conveyed perforating system, provides an overview of the nine (9) wells completed to date and describes the laboratory test procedures and results used to validate the use of a water-based fracturing fluid. Project cost savings are also discussed pertaining to the Total Cost of Service (TCS) differences between hydrocarbon and water-based fracturing fluids in a cold weather environment.