bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research, Test and Application on Enhancing Working Reliability of Pump Head for High-Pressure Water Injection Pump
Authors: Yang Fangyun , Wu Zhenya 
Published: December 2007

Abstract
The key factor to guarantee high-pressure water-injection pump's working reliability is operating life of pump head (valve box). This paper presents the pump head compound intensifying process, which is based on researches on fracturing mechanics, metallics, fatigue damage, metal intensification, finite element analysis and machinery manufacturing process. The process consists of two steps. Firstly, a hardening treatment is practised to the inner surface of pump head so that the surface has a compression stress field. Secondly, a sand blast treatment is practised to the inner surface to acquire optimal residual compression stress field. The process will highly enhance its fatigue fracturing resistance and stress corrosion (including hydrogen brittleness) fracturing resistance. The study shows the residual compression stress field formed by the sand blast treatment and -a phase change caused by plastic deformation are the key factors to enhance the fatigue resistance of pump head.
To develop deep zone reservoir, particularly the faulted block field, normally needs water-injection pressure of 40MPa. H i-pressure reciprocating water-injection pump manufactured by Zhong Cheng Company, Dagang Oil Field Group Co. Ltd., can perfectly meet the requirement. Nearly 2,000 units have been provided to domestic users in China, with a market share of 85%. Hekou Oil Production Headquarter of Shengli Petroleum Administration Bureau has taken a comparison test to our pump, which showed the pump increased averagely 11 t/d per pump. In Wennan Area of Zhongyuan Oilfield, the pump increased by 6 t/d. The applications have demonstrated that the key factor to influence the pump's working reliability is the working life of the pump head (valve box). On the basis of analysis the intrinsic rule and related factors affecting pump head working reliability, we put forward the self-enhancement process by thin shell hardening. The process prolongs its working life but the life clearance was not satisfied. Then we take some measures to imporve the process, inculding metallurgy quality and management, its working life is extended. Then after, the process is taken a test study, smallscale industrial test and large-scale extended application and finally reach a breakthrough.
P. 111
Developing Another Heavy Oilfield with Combination Directional Wells and Horizontal Wells -- Development program of QHD32-6
Authors: Jiang Wenxue , Li Yanbo , Chen Guofeng , Ji Ning , Chen Peng 
Published: December 2007

Abstract
Based on the detailed reservoir description, a reservoir simulation model has been built for the selection of production schemes, the division of layer developing series, and optimizing well patterns, well spacing and horizontal wells etc. The combination of both directional wells and horizontal wells is recommended for the development of QHD32-6 oilfield after the study.
P. 135
Evaluation of Horizontal Well Development in Ansai Extra Low Permeability Oilfield
Authors: Wu Zhiyu 
Published: December 2007

Abstract
Ansai oilfield is a marginal oil field with an extra low permeability in the economic and geologic viewpoint. The air permeability is 1.29 md and Kilinkenberg permeability is only 0.49 md. It is difficult to increase individual-well flow rate and to obtain economic benefits because of formation geology. In 1993, the first horizontal well SP-l was drilled in the South of the field with oil production equivalent to that of 4.5 vertical wells in the same block. In 1996, five horizontal wells were drilled and development test of horizontal well group was carried out in the North of the oilfield, in which the reservoir physical property is much poor.
This paper discusses the reservoir characteristics, oil production technology, injection-production performance and so on. The key point of the paper is the comprehensive evaluation of development results of horizontal wells, the main factors affecting production rate of horizontal wells are analyzed, and the feasibility of employing horizontal well to develop extra low permeability, thin pay zone in Ansai is also discussed.
P. 187
Research on the Method of Determination for Remaining Oil at Late Period of High Water Cut Stage
Authors: Du Qinglong , Qing Lu , Cheng Baoqing , Wang Quanlin 
Published: December 2007

Abstract
The method discussed in this paper is to research the relationship between water-out degree of various layers at different waterflood stage and influential factors (well location, sandbody type, communicating states with surrounding injectors and water injection distance) based on water-out behavior analysis of various layers in inspection wells drilled at different period, and to evaluate water-out degree by severe, mediate and weak or no levels for each layer in any well by using fuzzy comprehensive evaluation method and neural network pattern recognition technology, then to further determine remaining oil distribution in each layer. Practical verification of other inspection well and separate layer testing data are conducted. The coincidence rate is high. This method has been successfully applied in remaining oil research of Lamadian oilfield at late period of high water cut stage.
P. 197
Development Practice of Es3 2+3 Marginal Reservoir in Gaoshangpu Oilfield
Authors: Yu Shoude , Chang Xuejun , Liu Quanhai , Yuan Junxiang 
Published: December 2007

Abstract
Es3 2+3 reservoir in Gaoshangpu oilfield is a typical field with complex faulted block marginal. In the past ten years, we achieved scale development and gained better economical in Gaoshangpu oilfield by adopting modem reservoir description technology and characterizing the geological features accurately. At the same time, we used completing injection and production system step-by-step through encrypting well pattern and dividing layer series reasonably making practical development technology projection, and applying advanced technology.
P. 203
Flow Mechanism Investigation and Field Practice for Low Concentration Flowing Gel
Authors: Han Dong , Yang Puhua , Luo Youshong , Qingxia Weili , Qingxia Lin , Cheng Shaozhi , Shong Zhengyu , Tang Jinxing , Tang Xiaolei 
Published: December 2007

Abstract
The applications of flowing gel for modifying the water injection profile is a novel EOR technique developed in recent year. The features of this system are low cost, large application and it can solve the problems of short effective period, quick polymer production in polymer flooding. Therefore, it is of certain use in China. In the paper, the low concentration flowing gel was obtained by using organic metallic Cr3+-polyacrylamide system for the first time. The structure and properties of the gels were identified by modern analytical techniques of atomic force microscopy and dynamic rheological method. The large diameter sand pack displacement tests were carried out to investigate the flow mechanisms in the porous media. The results show that: flowing gel is a aggregate of cross-linked molecules with a radius of 30 m. Low concentrations gellant system can form into gel during its flow in porous media. And the gel formed is capable of flowing, and different from that formed from solutions. The flowing behavior of low concentration flowing gel in porous media is different from conventional polymer flooding. It can be described by the first, maximums and residual resistance factors. The field practice of injectivity test was carried out in Henan oil field. The radius of injection was 70m, injection period 60 days. After injection, pressure increased 2MPa, with an incremental oil production of 4 ton/d. It shows the injectivity is good.
P. 483
Liquid Carbon Dioxide Fracturing for Increasing Gas Storage Deliverability
Authors: Harris Ramon P. , Ammer James , Pekot Lawrence J. , Arnol Daniel L. 
Published: December 2007

Abstract
During the summer of 1995, National Fuel, through a Department of Energy (DOE) sponsored project for storage deliverability enhancement, began a stimulation project on three wells in Galbraith Storage Field. Galbraith, located in Jefferson County, Pennsylvania, consists of 26 active injection/withdrawal wells completed in the First Sheffield Sand at an average depth of 2,800 feet. Three of the active wells were fractured in the early 1980's using a gelled water fluid and approximately 20,000 pounds of sand. Several years of cleanup were required in all of these wells before the peak stimulation deliverability was experienced. The combined delivery from two of these wells was responsible for more than 40% of the field total. The fracture stimulation provided a significant increase from pre-frac deliverability. However, roughly 10 years of storage use and a coiled tubing cleanout were required before this level of increase was realized.
Three wells from the remaining 23 active were selected for the first liquid carbon dioxide fracture stimulations conducted in a storage field. Preliminary well test analysis indicated that permeability in the field was greater than anticipated, and deliverability was being adversely affected by a large skin. The fracture procedures were designed to produce short propped fractures to extend beyond near wellbore skin damage. The fracture gradient experienced was greater than 1, pushing the treating pressure to the maximum allowable for all of the jobs. As a result, the sand concentrations did not get as high as designed. The formation breakdown in one well was not sufficient for proppant to be run and very little deliverability increase was achieved at this well. However, deliverability increases at the other two wells were about 5 fold, roughly 5 MMcfd. Concerns that the carbon dioxide would not be recovered in a timely manner were put to rest after a few days as the concentration in the gas quickly fell below 3% and the wells were put back into service.
The level of immediate deliverability increase is what makes this technique attractive to storage operators. Because the pumped proppant was lower than anticipated, the longevity of the increase is suspect. Eighteen-month follow-up well testing has shown good maintenance of deliverability at the two propped wells and an increase in the deliverability at the unpropped well. Flow testing was conducted in July 1998, to evaluate the third-year performance. Additional details regarding the planning, testing, pumping, and evaluating of these jobs are discussed in the paper as well as a general review of the costs.
Collapse Behavior of Casings: Measurement Techniques, Numerical Analyses and Full Scale Testing
Authors: Assanelli A. P. , Toscano R. G. , Johnson D. H. , Dvorkin E. N. 
Published: December 2007

Abstract
The production of steel OCTG products with guaranteed external collapse pressure (high collapse casing) requires the implementation of an accurate process control. To develop that process control it is necessary to investigate how different parameters affect the external collapse pressure of pipes. Two dimensional finite element models provide an useful tool for performing the "first approach" parametric studies; however a bidimensional representation of the tube geometry (as used in many analytical and semi-empirical formulas) is not enough for determining the external collapse pressure of casings. We use three dimensional models to further investigate the effects of the casing geometry on its external collapse pressure. To acquire the data that dscribes the geometry of casing samples, we have developed an imperfections measurement system following previous developments by Yeh and Kyriakides. We also present finite element models of OCTG connections which are used as a tool for the evaluation of connections collapse pressure.
Relationship Between Polymeric Fragment Damage and Damage Removal and the Original Rock and Proppant Pack Permeability
Authors: DeVine C. S. , Tjon-Joe-Pin R. M. , Rickards A. R. 
Published: December 2007

Abstract
Fluid viscosity reduction is an important gauge of polymer degradation, and, although viscosity reduction does indicate that polymer degradation has occurred, reduced viscosity does not necessarily indicate that the proppant pack and the formation are undamaged. Polymer fragments which are "broken" from the gelled fluid no longer contribute significantly to fluid viscosity but may contribute to proppant pack and/or formation permeability damage, i.e. fragments may be "stuck" in pores and pore throats.
Carbohydrate analysis of post-fracturing flowback fluids yields valuable information regarding the abundance of mobile polymer fragments which are recovered subsequent to fracture stimulation. Gel breaker efficiency is characterized based upon the size distribution of generated polymeric fragments from both linear and cross-linked guar based fracturing fluids. Previous studies have demonstrated that a correlation exists between formation rock permeability and the degree of damage resulting from residual polymer fragment deposition -the greater the formation rock permeability, the greater the degree of damage to the formation.
In this study, results of core flow and fracture conductivity testing are presented in an effort to correlate clean up effectiveness to original rock and proppant pack permeability. Degraded and cross-linked low, near neutral, and high pH frac fluids were tested. In general, a greater percentage of regained permeability was noted for more severely (i.e. permeable) damaged rocks. Proppant pack studies showed a similar effect. Rocks tested in this study exhibited permeabilities from 3 md to over 2 darcies. Conductivity proppant pack baseline ranges were 250 to 500 darcies.
Data yield a semiquantitative model of the extent of formation permeability and conductivity damage and clean up that can be expected based upon the original rock permeability. Laboratory carbohydrate content data are compared with fracture flowback data, and field case histories, as applicable, are discussed.
Stripper Field Performance Comparison of Chemical and Microbial Paraffin Control Systems
Authors: Giangiacomo Leo A. 
Published: December 2007

Abstract
This paper reports the field performance results of a comparison of chemical and microbial paraffin control systems. The two systems were selected based on laboratory screening work. Well selection was based on production rates, produced fluids, and prior paraffin treatment history. The treatments were performed on similar groups of wells over the same period of time, using quantities and techniques recommended by the supplier specifically for the wells to be treated. The tests were conducted by the U. S. Department of Energy's Rocky Mountain Oilfield Testing Center at Naval Petroleum Reserve #3 in Natrona County, Wyoming.
The chemical system was applied to three stripper wells. The treatments utilized paraffin solvent and diesel and were pumped down the casing annulus of the wells. Initially, a smaller treatment was performed to clean up the wellbore and tubulars. Shortly thereafter a larger treatment was performed to clean up the perforations and near-wellbore area.
The microbial system was applied to four stripper wells. A dry medium containing microbes was mixed with produced water and pumped down the casing annulus. The wells were treated monthly for three months.
Production was monitored closely on all the treated wells prior to the treatment and for eight months thereafter. The study makes recommendations for choosing wells for paraffin treatments and for treating wells with microbial systems. It concluded that solvent treatments were capable of yielding larger production increases. Microbial treatments required lower capital investment and yielded lower initial production increases, but had a more sustained effect.
Downhole Capillary Soap Injection Improves Production
Authors: Awadzi Jacqueline , Babbitt Jess , Holland Steve , Snyder Kent , Saucer Tom , Latter Kelly 
Published: December 2007

Abstract
Liquid loading is an ever increasing problem as gas wells age and deplete. In tight gas reservoirs, liquid loading can adversely effect well performance for 3/4 to 7/8 of a well's 20 to 30 year life. A relatively new approach to unloading liquids had been to inject soap via a downhole capillary injection system. This approach has resulted in substantial and sustained production increases in East Texas Cotton Valley gas wells at depths of 8,500' to 11,000'. The production increases will impact both well life and reserve recovery. The East Texas Cotton Valley gas area contains 3500+ wells and it still continues to be an active development area.
The capillary stainless steel 1/4"-3/8" tubing is snubbed into the well inside the tubing. A downhole injection/check valve assembly is run on the end of the capillary tubing. Soap is then injected or siphoned from a chemical storage tank through filters to maintain solids-free fluids for injection. Injection can be easily maintained on a continuous basis to ensure consistent foaming action for unloading efficiency. The capillary string is easily installed and can be transferred from one well to another. In many cases the soap injection from capillary tubing has out performed the more conventional plunger lift.
The injection system is also very effective in treating downhole corrosion, paraffin and scale, buildup and in dissolving salt buildup. This capillary injection system could provide a new approach to solving many oil and gas well operating problems worldwide.
CO2 Gas Lift – Is It Right For You?
Authors: Martinez John 
Published: December 2007

Abstract
Gas lift can be installed in producing wells within a CO2 flood utilizing the nearly pure injection CO2 or the mixed hydrocarbon/CO2 gas returning to the production station. Lift gas injection rates can be varied to correspond to the water content resulting from the water-alternating-gas (WAG) results.
The lift equipment configuration options are:
standard installation with gas on the casing passing through a valve mandrel(s) gas conveyed by coiled tubing (strapped to the main tubing) to the valve mandrel coiled tubing hanging inside the main tubing with production flow in the annulus of these strings
Field installations of the two options at the top of the list have given good service and the last option is a common configuration for velocity strings in gas wells.
Gas lift as an artificial lift method can eliminate failures in pumps due to the CO2 or due to the gassy nature of the produced fluid. Chemical treatments can be transported downhole with the lift gas and used to control corrosion, paraffin, or asphaltine.
Gas lift is a flowing process, which must have adequate reservoir, and wellbore pressure to flow the fluids to the surface facility, whereas the pumping process has energy transmitted downhole to raise the fluid pressure. Wellbore pressure for pumps can be lower since the fluid need only flow from the reservoir to the pump intake.
Using Stimulation Expert System to Design Hydraulic Fracturing Treatments – Field Examples
Authors: Xiong Hongjie , Rahim Zillur 
Published: December 2007

Abstract
Stimulation Expert has been developed to aide the engineer design a stimulation treatment. The process involves calculation of injection and tubing pressure and tubular movements, selection of appropriate mode and methods of stimulation, and correct choice of treatment fluids, proppant, and pumping schedule. The program is user-friendly and the numerous databases and expert help facilities included in STIMEX™ make this program readily accessible to all level of engineers and experts in solving stimulation problems.
The Stimulation Expert system has been used for the design of stimulation treatments for oil and gas formations for a wide range of reservoir property. The expert help and technical advice received during the design process have been successfully used for the treatment designs. In the final phase of the design, the optimization method is used to predict the optimal treatment that should be carried out in the field.
Deepwater Well Control: Circulate With Both C&K Lines?
Authors: Christman Stan A. 
Published: December 2007

Abstract
In deepwater well control, choke and kill line friction becomes an increasingly important factor, particularly when the margin between mud density and the equivalent casing shoe fracture gradient is small. Using both C&K lines for flow is one of the options to reduce the friction loss, but the decision involves considerations that are affected by well and rig conditions. This paper reviews these considerations, including an interesting phenomenon called the ‘BOP Separator Effect’ that alters the flow distribution when two lines are used and the kick has free gas. This effect has been studied with computer modeling and appears to have the beneficial effect of reducing hydrostatic surface pressure fluctuations and hence facilitating choke adjustments. Also, the value of a pressure sensor in the BOP stack is addressed.
Modern Use of Closed-Loop Hydraulics for Controlling and Powering of Cylinder-Based Hoisting Systems
Authors: Rudshaug B. , Skibelid T. 
Published: December 2007

Abstract
The Maritime Hydraulics A.S RamRig© drilling concept is based on hydraulic cylinders as actuators powered by up to 3.4 MW of hydraulic power in a closed loop hydraulic system. This synthesis of well-known technology allows for the use of integrated active and passive heave compensation, as well as the storing and reuse of energy from the lowering phase of an operation. The RamRig concept makes mechanical brakes and clutches obsolete, since hoisting and lowering of the load is controlled solely by the closed loop hydraulics. This decreases the number of critical mechanical components in the hoisting system to a minimum. Safe handling and emergency shut down of extreme amounts of hydraulic power is taken care of by cartridge valves, which make rerouting of hydraulic power possible with minor losses of transferred effect.
A Radical Approach to Offshore Activities in the New Millenium
Authors: Mitchell C. , Chiesa G. 
Published: December 2007

Abstract
The high costs of offshore activities, particularly deepwater drilling, are currently forcing oil companies to consider new technologies and new ways of operating in an effort to reduce costs of finding oil in even deeper waters. Shell and Saipem have been working together for the last 18 months considering the idea of a Subsea Drilling rig. This work has indicated that subsea drilling is a feasible concept, which has a number of benefits over conventional drilling, although the cost to construct a fully capable rig, coupled with the technical risk associated it, means that it is unlikely to happen today. However, for rank exploration work, where success is on average very low (20-30%), it is proposed that a very small subsea rig, with the capability to gather a minimum of reservoir data through a minimum diameter hole, might be an economically attractive solution, which will enable true low cost exploration drilling.