bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Extension Of The Pollard Analysis Method Of Well Pressure Build-Up And Drawdown Tests
Authors: Pirson Richard S. , Pirson Sylvain J. 
Published: December 2007

Abstract
The Pollard method for analyzing well pressure drawdown and build-up tests presented in 1958 permits the calculation of the well skin effect and of the volume of the coarse pore volume system affected by the well. It was devised primarily to design and predict results of acid treatments. The present study extends the Pollard analysis to the calculation of the fine pore volume system (often called "matrix" porosity) and to the calculation of the "radius of influence" of a well before and after well stimulation treatment. The method permits to ascertain if a sufficient number of wells are drilled in order to drain effectively a given field or lease. The extension of the Pollard method is based on laboratory tests made with electric analogs of the various simulated porous systems. Limitations and field examples from fractured and vuggy reservoirs are given.
In many reservoir engineering calculations it is important to know the pressure variations since many of the variables in reservoir engineering are dependent on pressure. It is well known that reservoir pressure in a producing or in a shut-in well varies with time, but it is not so well known how exactly the reservoir pressure varies mathematically with time. In fact, as will be discussed later, several papers have been written outlining various methods of analyses of pressure build-up curves.
Benefits of Linear Bivariate Log Analysis Models
Authors: Collins H. Neal , Pilles D. 
Published: December 2007

ABSTRACT
As computerized log analysis becomes more sophisticated it becomes more difficult for the log analyst to assess the validity of the models being used. This paper suggests that current efforts to define and display uncertainty criteria should be increased. Two samples are presented to show how functional analysis, applied to linear bivariate models, can provide cap-sulized information useful to the analyst in monitoring input data and testing model validity.
Trends of the PVT-Properties of the Gas-Oil Reservoir Fluids and the Thermodynamic Effects Occurring at the Separation of the Produced HC Mixtures
Authors: Brusilovsky A. I. , Kaplan A. L. , Nugayeva A. N. 
Published: December 2007

Abstract
The paper offers methodological approaches and describes the results of integrated use of data of production, laboratory and theoretical studies of the properties of the natural HC mixtures produced in the West Siberian oil and oil-and-gas fields.
It shows that in order to increase dramatically the oil production, the optimal pressure should be defined for the first-stage separation at the booster pipeline pumping station when producing light oil with high solution gas-oil ratio.
One-Trip Sand-Control / Liner Hanger / Big-Bore Completion System
Authors: Hoffman C. R. 
Published: December 2007

Abstract
This paper introduces a revolutionary completion system which, by design, replaces conventional TCP perforating and gravel packing through a technique using hydraulic pressure only. This technology also eliminates formation damage caused by perforating and reduces skin values. It is a new-generation, screenless sand-control completion system.
During the development of this technology, several versions were tested, leading to the system offered today. A telescoping conduit containing sand-control media comprising stainless steel beads was chosen for its durability, erosion resistance and plugging resistance. The system contains no explosives whatsoever; therefore many issues pertaining to this were eliminated.
A JIP (Joint Investment Project) team consisting of three major operators, a service company and an independent tool manufacturer was formed with several criteria to meet. The team was posed with the task of developing a system whereby formation damage was eliminated and skin values were greatly reduced. Conventional perforating is the major cause of formation damage, so the primary goal was to eliminate this and still be able to achieve connectivity with virgin reservoirs and maintain full bore production and/or injection rates.
Also, one-trip capability and user-friendliness was of primary concern as with all new technologies; if this system were to cost operators more throughout the completion of any given well, it would have no merit in the marketplace. Therefore the system was designed around conventional liner and cementing techniques, as these are of vital importance in the success of a quality completion.
Development of Moomba North Gas Field: Lessons Learned from Integrated Study Followed by an Infill Drilling Campaign
Authors: Herweijer J. C. , Barley M. , Bainbrigge P. , Herries T. 
Published: December 2007

Abstract
Field development planning based on integrated studies, including construction of a 3D geo-model, is an accepted standard for development of larger assets. The need to keep field development plans ‘evergreen’ is well recognized, but often difficult to realize in practice.
This paper will focus on the results of a drilling campaign that followed an integrated study previously described in SPE paper 62901(Herweijer et al., 2000). As with many drilling campaigns, the results covered a range from very positive to negative outcomes. This paper will show how the result of the campaign, which was an overall success, was affected by:
– The modeling process, which assumed a base case with perturbations. It became anchored on a specific, optimistic, fluid contact scenario, rather than including a realistically wide range. – The process of multi-disciplinary work, which, although rigorous, did not in itself guarantee that a realistic range of scenarios had been covered. – Changes in team membership prior to execution of the infill campaign. This lead to a partial lack of ownership, resulting in the missing of signposts that could have lead to re-tuning the campaign by accounting for more downside scenarios. – The relatively elaborate study and modeling process, which discouraged updating and hence lead to poor integration of some early negative drilling results into the model.
The conclusion of the paper is that the whole study became somewhat ‘model-centric’. The model served as an unbeatable ‘truth’: trusted more than pre-model mapping, not fully connected to post-model ‘mass production’ infill drilling results, and used on problems to which it was not suited.
As a result of the lessons learned we have been able to assess the real value of knowledge continuity and model ‘ever-greening’ from early stages of development through to later ‘harvest’ drilling.
Study of the Lifting Technology for Numerical Control Reciprocating Electric Submergible Pump
Authors: Wang Dejin , Wang Zaishan , Lu Dongfeng , Ji Shengzhu , Hou Weiqian , Ge Dongyuan , Guo Shiying 
Published: December 2007

Abstract
Now, the technology of pumping unit-deep well pump is widely used in Daqing Periphery oilfield. But the average system efficiency is only 7.8% because of the deep of the well, the consistency of the oil and the low output of each well. The main reason of changing the deep well pump is broken off, separated and deflected abrasion in the upside of plunger and rod system. It is about 30.4% in all operating wells in 2004 and 32.8 percent in 2005 in NO.8 Oil Production Company. It leads to high cost in production and affects the economic benefit.
Research content:
This system is composed of direct current electromotor, frequency conversion control system and suitable pump. The stator of direct current electromotor is connected with the tubing underside of the pump. The rotor drives the plunger of the pump to reciprocate along axial way(direction) to lift the oil. The control system on the ground can change the pump speed to regulate the theoretical discharge capacity.
Laboratory experiment:
Place the electromotor into the oil which temperature is 60°C and pressure is 25Mpa, the insulating resistance is 2500MΩ after 240 hours. Simulating the real well with the 28mm pump until the pressure of well-head is 40Mpa, which is equivalent to 2.3t lift power. When the pressure of the well-head is 20Mpa, the pumping efficiency is 81%.
Field experiment:
There were 10 wells in this test in August 2004. The pump setting depth was about 1450m. The daily production was 5.7m3. The pumping and system efficiency was 82%, 31%, respectively. It can economizes about 27% in investment, 30% in run cost and 50% in power compared with the cross-model pumping unit.
Conclusion:
This technique adapts to the well which production is below 20t. It is a substitutive pumping unit for the low production, middle or deep wells. This technique need not pump rod to transmit power. It can reduce the lost of stroke, increase the pumping and system efficiency and decease the repairing cost which is caused by pump rod. Because the cluster direction and horizontal wells are increased year by year in Daqing Periphery Oilfield, this technique can lift the oil in each deep due to non-rod transmission.
Burning Reserves for Greater Recovery? Air Injection Potential in Australian Light Oil Reservoirs
Authors: Hughes B. L. , Sarma H. K. 
Published: December 2007

Abstract
Air injection is an Enhanced Oil Recovery (EOR) technique with limited exposure in the Asia-Pacific region and no previous application in Australia. Analogy with successful air injection projects in the USA, suggests that it could be a suitable EOR process for onshore light oil fields in Australia; no evaluation has been conducted to date.
Using open file data, high level screening criteria are used in this study to identify prospective petroleum basins, and an individual candidate reservoir is examined through a simulation study. Key issues in the application of the technique are discussed, as are directions for implementation in Australia.
Air injection involves the continuous injection of high-pressure air into the reservoir. The oxygen in the air reacts with the reservoir crude, consuming 5-10 % of the Original-Oil-In-Place (OOIP) and generating flue gases in-situ. This creates a gas drive process and acts to re-pressurize the reservoir. The process does not require water as a mobility control agent; a significant advantage in water-scarce Australia. It could also replace hydrocarbon (HC) miscible floods, freeing cleaner HC gases for energy use. Ideally the process is suited to deep, high-temperature, light oil reservoirs, and is applicable to both secondary and tertiary recovery.
The Cooper-Eromanga Basin, Carnarvon Basin (Barrow Island) and the Surat-Bowen Basin were identified as the most prospective. The simulation study conducted for ‘Reservoir A’ in the Cooper Basin indicated the potential for spontaneous ignition and propagation of a stable combustion front within the reservoir; hence it is a potentially good candidate for EOR by air injection.
Given the ‘high’ oil price and maturity of Australia's oil provinces, significant value is associated with EOR. Air injection is potentially suitable for Australian onshore application. The process warrants further evaluation and consideration as an alternative to accepted EOR techniques.
Hydraulic Fracturing of Miocene and Oligocene Sandstones in the Taranaki Basin, New Zealand
Authors: Green D. , Seanard K. , Martin A. N. 
Published: December 2007

Abstract
The Taranaki district of New Zealand, located in the southwest corner of the North Island, is the center of the country's emerging oil and gas industry. Over the last five years, an active campaign of propped hydraulic fracture stimulation has been performed in the early Miocene and Oligocene sandstones, located towards the south of the Taranaki sedimentary basin. Although hydraulic fracture stimulation is relatively rare in New Zealand, it has shown itself to be highly effective. This is due, in part, to the application of sound scientific and engineering principals, rather than the stochastic approach that is often applied when fracturing. The formations themselves are highly complex and consequently the techniques used for fracturing are at the cutting edge of today's fracturing technology. The results of the programme have significantly benefited from this methodical and progressive approach.
This paper deals with the various aspects of fracturing into these formations and the lessons learned, including the equipment and methods used. It also details how the methods have evolved and allowed treatments to increase in both size and effectiveness, using numerous case histories. These detail what can be achieved in an area that is generally unfamiliar with the processes involved, when an existing technology is systematically applied.
Formation Damage Induced by Fracture Fluids in Coalbed Methane Reservoirs
Authors: Chen Z. , Khaja N. , Valencia K. L. , Rahman S. S. 
Published: December 2007

Abstract
This paper presents the results of a laboratory study on the effect of different fracture fluid systems on permeability impairment of a typical coalbed methane (CBM) reservoir. These fluid systems include conventional gel fluids (linear and cross-linked gel), gel fluid with surfactant and a viscoelastic fluid system. A series of flow tests on coal plugs were conducted under simulated reservoir conditions to assess permeability reduction due to matrix swelling and cleat plugging by gel fluids. Tests included surface behavior of different fracture fluids and surfactants on coal surface, degrees of matrix swelling and plugging of fractures and cleat systems by fracture fluids.
The results of these tests have shown that permeability impairment induced by matrix swelling is highly irreversible. This irreversible damage can be prevented to a certain extent by conventional practices of adding certain types of salt (such as KCl) into fracture fluids. Both linear gel and cross-linked gel fluids cause a significant reduction (around 70%) in permeability of CBM reservoirs. Addition of KCl along with certain types of surfactants to gel fluid can marginally improve gel clean up. However, the permeability impairment could be as high as 60%. With the use of viscoelastic fluid system, on the other hand, permeability impairment can be as little as 20 to 30%. This means the viscoelastic fluid system has a great potential in reducing permeability impairment which in turn can help rapid dewatering from CBM reservoirs and increase production.
Developing a Fractional Flow Curve from Historic Production to Predict Performance of New Horizontal Wells, Bekasap Field, Indonesia
Authors: Sitorus J. , Sofyan A. , Abdulfatah M. Y. 
Published: December 2007

Abstract
A fractional flow curve (fw versus Sw) is used to describe the immiscible fluid displacement process. Developing a representative fractional flow curve for a specific reservoir can be quite challenging when fluid and special core analysis data is limited. This paper demonstrates a technique to develop a reservoir scale fractional flow curve from historic production data. The curve becomes the basis for an analogous model that allows the estimation of oil rate production forecasts and reserves for existing or proposed new wells. In addition, relative permeability curves can be generated based on the resultant fractional flow curve. A comparison with relative permeability curves obtained from special core analysis can be made to provide increased confidence.
In order to develop an fw (water cut) versus Sw (prevailing water saturation) relationship from historical production data, a simplified material balance algorithm and the Corey equation are solved simultaneously. A number of iterations are made until a reasonably good match is achieved. In waterfloods and strong water drive reservoirs, the total fluid production rate can be assumed constant. Therefore, it is possible to estimate the future oil production rate profile for new or existing wells using the reservoir scale fractional flow curve.
The results compared favorably with forecasts developed using our in-house simulation model and commercial material balance software with less time and effort. This method was successfully used to examine the performance of over 30 horizontal wells in the Bekasap field. The method also served as a simple preliminary tool to identify in-fill development well opportunities in the Menggala South and Waduk fields, two other mature oil fields in Sumatra, Indonesia.
Innovative Use of Expandable Sand Screens Combined With Propped Hydraulic Fracturing Technology in Two Wells With Intelligent Completions in the Egret Field, Brunei: Challenges, Successes, and Best Practices Learned
Authors: Abdul-Rahman Sakamrin , Lim Derek , Lim Jit Juan , Ong Kuo Chuan 
Published: December 2007

Abstract
Oil and gas producers have long been looking for effective sand control methods that allow completion flexibility and improved productivity throughout a well's lifecycle. This paper discusses the many challenges encountered during the planning and completion of two wells in the Egret Field in Brunei, operated by Brunei Shell Petroleum (BSP), how the challenges were addressed, and the best practices identified for future operations.
Sand-control techniques such as an extension packing and hydraulic fracturing were evaluated to help minimize the risk of fines plugging because of the high fines content (10 to 15%). To minimize well interventions while maximizing data gathering, an intelligent-well completion using surface-controlled sub-surface variable chokes for internal gas-lift and surface controlled sub-surface fixed chokes was proposed.
Another design challenge was that conventional wire-wrapped screens would have insufficent clearance to accommodate intelligent-well completions. A feasibility study recommended a combination of expandable sand screens (ESS) and propped hydraulic fracturing in a cased-hole environment.
Two wells were planned in which three oil reservoirs would be completed and produced commingled, using one gas reservoir as a lift gas source. Expandable sand screens would be installed across the perforated intervals inside a cemented 9-5/8-in. casing.
With a skin of less than +1 on all completed intervals, the productivity of both wells has been excellent. The success has been attributed to the unique combination of ESS and hydraulic fracturing.
One-Molar Salt Solutions Used for Clay Control in Water-Based Frac Fluids in Western Siberia
Authors: van Gijtenbeek Klaas , Neyfeld Alla , Prudnikova Antonina 
Published: December 2007

Abstract
The use of oil-based fluids in the western Siberian oil industry for hydraulic proppant-fracturing treatments in water-sensitive formations to prevent clay swelling was widespread. The added advantage of using oil-based fluids for cold weather conditions is obvious. However, with the growing number of treatments and increasing treatment sizes, the use of oil or diesel, from an economical point of view, becomes less attractive. In addition, there is a growing environmental concern with respect to using oil for mixing and pumping fracturing fluids. The use of gelled water is cheaper, and from an environmental perspective, more attractive.
The addition of 2% KCl to water-based fracturing fluid for temporarily controlling clay swelling is widely accepted as a standard practice. In situations where water-sensitive sandstone formations have been treated and longer protection has been required, very often additional clay stabilizing agents are added to the water-based fracturing fluids.
Research on the technology of matrix acidizing treatments has revealed that the use of 2% KCl transforms into 1.5% saltwater as a result of ion exchange. The 1.5% saltwater solution is too weak to prevent clay swelling. Clay swelling can be prevented using a 1 molar (7%) KCl salt solution.
Based on acidizing treatment research, it was decided to use 7% KCl as a temporary clay control additive in water-based fracturing fluids for treatments in western Siberia. One-molar salt solutions have been used for all the treatments performed during the last four years. Model 50 viscometer measurements were made to identify the influence of increasing KCl concentration from 2% to 7% on the viscosity development of borate crosslinked fluid. Water retention problems have not been reported since 7% KCl has been used.
From a study of the pre- and post-fracturing production data, it was apparent that in general the percentage of water produced with the oil did not reduce. It is postulated that this is an indication of good temporary clay control. This study excluded treatments that clearly contacted a water-bearing zone.
P/Z Abnormally Pressured Gas Reservoirs
Authors: Ramagost Billy Paul , Farshad Fred F. 
Published: December 2007

ABSTRACT
The P/Z versus cumulative gas production plot is a commonly accepted method used to obtain original gas in place in volumetric (no water drive) gas reservoirs. Many petroleum engineers apply this method to abnormally pressured reservoirs which can lead to errors of up to 100% in the original gas in place extrapolation. The problem is that the conventional P/Z plot in abnormally pressured reservoirs must be adjusted for rock and water compressibility to obtain reasonable estimates of original gas in place.
A normally pressured reservoir will have an initial pressure gradient between 0.43 and 0.50 psi/ft. Reservoirs with pressure gradients greater than this are abnormally pressured. In the Gulf Coast area of Louisiana and Texas, pressure gradients can be very close to overburden pressure gradients with some of the gas reservoirs having gradients of 0.85 psi/ft. or higher.
In abnormally pressured reservoirs the reservoir fluids support additional pressure as is evident by pressure gradients of 0.85 psi/ft. The gas compressibility can actually approach formation compressibility in abnormally pressured reservoirs. This makes it important to include both formation and water compressibility in the P/Z plots when trying to estimate original gas in place in abnormally pressured reservoirs.
This paper presents a new technique for predicting performance of an abnormally pressured gas reservoir. This method maintains the old straight line relationship for conventional P/Z's in normally pressured reservoirs and allows direct extrapolation of original gas in place in abnormally pressured reservoirs by accounting for rock and water compressibility in the adjustment factor term. Thus, in abnormally pressured reservoirs, the early prediction of original gas in place from the P/Z curve is one of the main reasons for using this method.
This method has been successfully applied to three abnormally pressured reservoirs. They are the North Ossun Field in Louisiana, the Anderson "L" gas reservoir in South Texas, and to a Louisiana offshore gas reservoir. The results of the application of the new method and a comparison of predicted performance in abnormally pressured reservoirs using this technique and the conventional P/Z method will be presented in this paper.