bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of Oil in Place, Ratio of Initial Free Gas to Oil, Reservoir Rock Properties from Limited Pressure Data
Authors: Ojo Kolawole P. , Djebbar Tiab , Osisanya Samuel O. 
Published: December 2007

Abstract
This study presents a pressure transient analysis technique for determining the initial oil-in-place and the ratio of initial gas to oil, within the drainage area of the test well. The method is based on a combination of the material balance equation, the cumulative production history, individual well rate history and PVT data of the reservoir, with limited well test pressure data. The solution method considers the variable rate production history of each of the wells and combines this data with a global pressure data analysis approach as opposed to the usually employed approach of applying each method in isolation, which often produces erroneous results.
The analysis procedure allows every detail of the reservoir development, rate changes at every well from inception, global (reservoir wide) and local (individual well) fluctuations in pressure to be included in the overall results. Local variations in reservoir rock properties at the well locations are also accommodated in the method. By modifying the analysis technique used for solving the linear material balance, a method is derived that allows the simultaneous determination of the original oil-in-place, and the initial ratio of free gas to oil in the reservoir, without the previous knowledge of one or the other from an independent source, a requirement that is often needed for such solution. A Dynamic Material Balance Program (DMBP), a Visual Basic based program, was developed to implement the solution procedure presented in this paper.
Dynamic and Static Fluid Loss Properties of Novel Starches Prepared using Reactive Extrusion Technique
Authors: Amanullah Md. , Yu Long 
Published: December 2007

Abstract
Several novel fluid loss additives have been developed using agricultural resources grown in Australia. The fluid loss controlling performance of the novel mud additives were evaluated and compared with the fluid loss controlling performance of a widely used modified starch. The evaluation of the effect of starch concentration on the fluid loss behaviour of water-based muds indicates a working concentration range of 2-8 ppb for most of the novel starch products for different level of fluid loss control. Experimental results indicate that some of the newly developed starches show static and dynamic fluid loss characteristics similar to or better than the static and dynamic fluid loss characteristic of a widely used modified starch used by the mud industry. The static fluid loss properties measured after thermal treatment at different temperatures indicate that the newly developed starch products can be used as fluid loss additives for drilling boreholes having bottom hole temperature up to 150°C. The dynamic fluid loss property of the novel starches measured at 80°C thermal condition indicate that the newly developed products have similar or better dynamic fluid loss control properties than the currently used modified starch.
A New Relationship of Rock Compressibility with Porosity
Authors: Li Chuanliang , Chen Xiaofan , Du Zhimin 
Published: December 2007

Abstract
This paper presented a new relationship of rock compressibility with porosity, which is a new formula deduced after a theoretical study of mechanics of porous media. The new formula of this paper incorporates two parameters of rock: the elastic modulus and the Poisson&s ratio, which are easier to measure in laboratory than compressibility itself. According to the new formula of this paper, rock compressibility increases as porosity increases, while the conventional empirical formula displays the reversal. The new formula also shows that rock compressibility depends on the rigidity of rock skeleton. According to the new formula of this paper, compressibility of rock in normal range of reservoir porosity is quite smaller than that of reservoir liquids, while the conventional empirical formula tells that compressibility of rock is usually larger than that of reservoir liquids. The new formula can explain many phenomena that the conventional empirical formula can not and can also provide correct values of rock compressibility for reservoir engineering research.
Optimized Exploitation of Gas-Condensate Reservoirs Using Neuro-Simulation
Authors: Ayala Luis F. , Ertekin Turgay , Adewumi Michael 
Published: December 2007

Abstract
Gas-condensate reservoirs have been the subject of intensive research throughout the years as they represent an important class of the world's hydrocarbon reserves. Their exploitation for maximum hydrocarbon recovery involves additional complexities that cast them as a different class of reservoirs - apart from dry-gas and black-oil reservoirs. Gas-condensate reservoirs are good candidates for compositional simulation studies as their depletion performance is highly influenced by changes in fluid composition. Often times, highly sophisticated and computationally intensive compositional simulations are needed for the accurate modeling of their performance, phase behavior, and fluid flow characteristics. The desirable outcome of a simulation study for gas condensate reservoirs is the identification and development of the best operational production schemes that maximizes hydrocarbon recovery with the minimum loss of condensate at reservoir conditions. However, compositional simulations are demanding in terms of computational overhead, manpower, and software and hardware requirements. Artificial neural network technology (soft-computing) has proven instrumental in establishing expert systems capable of learning the existing vaguely understood relationships between the input parameters and output responses of highly sophisticated hard-computing protocols such as compositional simulation of gas-condensate reservoirs. In this study, we conduct parametric studies that identify the most influential reservoir and fluid characteristics in the establishment of optimum production protocols for the exploitation of gas-condensate reservoirs. During the training phase of the artificial neural network, an internal mapping that accurately estimates the corresponding output for a range of input parameters is created. In this paper, a powerful screening and optimization tool for the production of gas-condensate reservoirs is presented. This tool is capable of screening the eligibility of different gas-condensate reservoirs to exploitation as well as assisting in designing the optimized exploitation scheme for a particular reservoir under consideration for development.
Determination of Gas Permeability of Tight Reservoir Cores without Using Klinkenberg Correlation
Authors: Li Shuliang , Dong Mingzhe , Dai Liming , Li Zhaowen , Pan Xuefeng 
Published: December 2007

AbstractThis paper reports the laboratory measurements of gas permeability for tight reservoir core samples with various upstream, downstream, and average pressures. Measurements are conducted with backpressures from atmospheric pressure up to 9.3 MPa. It is found that exerting a backpressure at the outlet of the core sample can effectively reduce the gas slip effect and improve the permeability measurements. When the backpressure reaches a certain level, defined as the minimum backpressure, the gas slip effect can be eliminated so that non-slip gas permeability can be obtained without using Klinkenberg correlation. When the backpressure exceeds the minimum backpressure the measured non-slip permeability is a constant for a given core sample. From this finding, a method of directly determining gas permeability of tight reservoir cores is provided. The experimental results also indicate that the minimum backpressure increases with decrease in permeability of tight reservoir cores. The concept and technique can be applied in the measurement of effective/relative gas permeability in multiphase systems where Klinkenberg correlation cannot be used to correct the gas slip effect.
Reservoir Porosity and Permeability Estimation from Well Logs Using Fuzzy Logic and Neural Networks
Authors: Lim Jong-Se , Kim Jungwhan 
Published: December 2007

AbstractPetroleum reservoir characterization is a process for quantitatively describing various reservoir properties in spatial variability using all the available field data. Porosity and permeability are the two fundamental reservoir properties which relate to the amount of fluid contained in a reservoir and its ability to flow. These properties have a significant impact on petroleum fields operations and reservoir management. In un-cored intervals and well of heterogeneous formation, porosity and permeability estimation from conventional well logs has a difficult and complex problem to solve by statistical methods. This paper suggests an intelligent technique using fuzzy logic and neural network to determine reservoir properties from well logs. Fuzzy curve analysis based on fuzzy logics is used for selecting the best related well logs with core porosity and permeability data. Neural network is used as a nonlinear regression method to develop transformation between the selected well logs and core measurements. The technique is demonstrated with an application to the well data in offshore Korea. The results show that the technique can make more accurate and reliable reservoir properties estimation compared with conventional computing methods. This intelligent technique can be utilized a powerful tool for reservoir characterization from well logs in oil and natural gas development projects.
An Innovative Approach to Assessing Miscible Flooding in a North African Field
Authors: Thompson Maggie , Bird Peter 
Published: December 2007

Abstract
This paper describes an innovative approach to assessing the viability of an EOR scheme in a sedimentary sandstone reservoir and making strategic decisions regarding the field development. The study involved: a series of workshops involving all disciplines of the operational team, EOR experts and facilitators; screening studies to identify the most likely EOR processes for the field; detailed sector and full field modelling; value modelling; and the construction of a decision risk model incorporating results from all stages of the assessment to provide a tool that the operator can use to make complex decisions. This paper concentrates on the initial workshop, detailed simulation modelling and the decision risk modelling.
The initial workshop gathered knowledge from all disciplines and set objectives and actions for the project.
A miscible gas injection project has been simulated at three different levels of detail. The finest model incorporates the very detailed geology associated with festoon cross bedding. The next level of modelling concentrates on a sector from a selected region between two wells incorporating explicit shale and channel features to ensure accurate modelling of gas flow mechanisms. Finally a full field model was constructed to honour the flow mechanisms observed in the fine scale modelling.
The decision risk model includes both "soft" and "hard" data. It incorporates the experience of the whole asset team and is able to investigate a range of different options and decisions. Production profiles from the simulation models are incorporated and algorithms are used to generate profiles for scenarios not investigated through simulation. The model can assess the value of a range of different field options taking due account of the risks and benefits.
Onsite Treatment of Oily Drilling Waste in Remote Areas
Authors: Barnes Gary R. 
Published: December 2007

Abstract
There are many examples of remote areas where oilfield drilling is undertaken Western Site Technologies Inc. (WST) has had experience in many areas world wide, however our main scope of treatment has taken place in the Northern Alberta and the North West territories regions of the Alberta Petroleum basin.
The Alberta petroleum basin is mature and any new prospects explored by Western Canadian companies tend to be located in areas and formations that represent difficult drilling conditions. An example of this situation is the active Belly River play, with its sensitive shales. Advanced recovery methods in mature fields often involve horizontal or inclined holes, particularly in the heavy oil regions.
To overcome excessively tight holes, avoid stuck pipe, avoid excessive hole caving and drill string drag problems, the use of oil-based mud has become more widespread than at any time in the past.
Improved Procedures for Estimating the Erosional Rates in High Offtake Gas Wells: Application of University of Tulsa Flow Loop Derived Correlations
Authors: Terziev Ivo , Taggart Ian 
Published: December 2007

Abstract
High rate offtake gas and gas condensate wells require both hydraulic and erosive issues to be addressed. The erosional aspects are particularly difficult and require special attention in high velocity areas if solid particles are present.
In the past, industry has attempted to handle the problem through API-RP14E, however; this standard has been widely accepted as conservative and physically unsound when applied to gas or gas condensate fluids, because it does not account for solid particle impingement. Since then, numerous models and correlations have been developed to predict wear rates in various tubing configurations.
The Tulsa work appears most comprehensive but there is little published information on how to apply many of its findings and present the results of erosional calculations in a form suitable for well design and field development planning.
This paper uses the Tulsa erosional work and presents a consistent methodology for predicting and displaying the erosion rates in a number of high offtake big bore well designs when solids production and liquid loading are present. The ideas and procedures developed here can be used with other wear estimation methods. The use of tolerable erosion (or sand) rate strategy as opposed to previously adopted (and widely used) "maximum solids free rate" approach is advocated.
The difficulties with prescribing the C constant in API RP14E are discussed and alternative derivations based on friction factors are presented. Subsequent sections consider examples of alternative gas well design, some of which use big bore technology, to demonstrate an application of a staged design process. The stages cover hot spot analysis, wear estimates and required erosional allowances before proposing an operating/monitoring strategy.
Simulation Investigation of the Feasibility of Simultaneous Hydrogen Sulfide-Water Injection to Improve Oil Recovery
Authors: Shedid Shedid A. , Abed Abdulla A. 
Published: December 2007

Abstract
Over the past several years, considerable attention has been devoted to the dangers of hydrogen sulfide during different phases of the oil industry, including drilling, completion, work-over operations, processing and transportation. These dangers are well understood and have been the subject of numerous field case histories and scientific studies. On the other side, a little or almost no attention is devoted to investigate the possible positive applications of hydrogen sulfide in the oil industry as an injectant to improve oil recovery.
A variety of techniques have been used to improve oil recovery from reservoirs in which there is no longer oil flow by natural forces. Water and/or gas injection(s) have been used successfully to improve the oil recovery of depleted reservoirs. The major goals of this simulation study are to investigate the feasibility of water, sour gas, and simultaneous hydrogen sulfide-water injection into oil reservoirs to improve oil recovery. Furthermore, the influences of water injection rate, hydrogen sulfide concentration and applied gas injection rate on oil recovery are studied. To achieve these purposes, a three-dimensional simulation model was developed using actual field data of an oil field in the United Arab Emirates. This simulation model was used to test the feasibility of simultaneous hydrogen sulfide-water injection to increase the oil recovery.
The results indicated that injection of water, or sour gas (hydrogen sulfide), or simultaneous hydrogen sulfide-water into oil reservoir increased oil recovery. This increment in the oil recovery due to hydrogen sulfide and/or simultaneous hydrogen sulfide-water injections were attributed to higher molecular weight of hydrogen sulfide in comparison to methane and increment of reservoir potential. The increase of gas concentration and/or injection rate increased the oil recovery. The application of the suggested technique is expected to increase oil recovery and also maintain reservoir pressure.
Intelligent Technology, Well Management Miracle - Fact or Fantasy
Authors: Davies John , Birch Bill 
Published: December 2007

Abstract
Despite the very substantial sums invested in its development during recent years, and in spite of the fanfares heralding its arrival, the uptake of "intelligent" or "smart" well technology, particularly the so-called "high end" devices, has been sluggish at best. If the claims made by the suppliers are to be believed, it would appear that the main reasons for this poor uptake are risk aversion and/or lethargy amongst the Operators.
This paper challenges these assertions, suggesting alternative reasons why interest remains muted, but also proposes potential solutions. Although risk aversion is almost certainly a contributory factor, the primary contention is that the market was never properly researched, or understood (value and cost drivers), and thus the wrong technology may have been developed and promoted. Why this might have happened is open to conjecture; however ineffective customer engagement at the outset, resulting in a misalignment in terms of required functionality, incompatibility with new generation well designs or simply that the development of this technology happened too late, are all postulated as possible causes.
Whatever the reasons, the ability to remotely monitor and control wells, and individual intervals, remains a key enabler for the optimal, economic development of many assets. However, unless measures are taken by suppliers to fully understand the market, and develop equipment with the appropriate functionality, it is likely the technology will remain niche and have minimal long term industry impact. On a brighter note, it is believed that new generation concepts are emerging that, if exploited coherently, have the capability of unlocking the value that the first generation technology was expected to deliver.
The purpose of this paper is thus not to stifle technological innovation, but to challenge the value of the current intelligent well toolbox, and promote potential alternatives that have higher value to both Vendor and Operator.
The Planning and Installation of a Hydraulically Operated (Intelligent) Completion - Offshore NW Australia
Authors: Guatelli Victor J. , Lay Kevin R. 
Published: December 2007

Abstract
In February 2004 a hydraulically operated completion was installed in the Scindian-4 well offshore North Western Australia. The completion design allows the Operator, BHP Billiton Petroleum (BHPB) to selectively produce two separate reservoir intervals without the requirement for a rig based intervention into this subsea well.
The Scindian-4 completion represents the first use of this technology (often referred to as Smart Well or Intelligent Completion) in Australia although BHPB operates a number of other intelligent wells elsewhere in the world.
This paper details the design, planning and execution of the subsea completion and covers lessons learnt during the installation phase. Particular emphasis is placed on how the completion was designed to achieve its goals and how the technology was incorporated into the existing infrastructure of this mature field.
The installation of the Scindian-4 completion will help optimise production from the field and facilitate the acceptance and use of this technology in future projects.
Decisions and Uncertainty Management: Expertise Matters
Authors: Malhotra Vinod , Lee Michael D. , Khurana Ashok 
Published: December 2007

Abstract
The oil industry loses an estimated US$30 billion or about 25% of its annual upstream expenditure due to poor decision outcomes1. This provides a strong incentive to study decision improvement initiatives. While there has been a significant improvement in decision-making, it has been slow and in small steps. Perhaps a paradigm shift maybe necessary to cope with an environment that is likely to become even harsher in future. We believe industry decision experts have overworked the technical and economic factors while largely ignoring individual expertise, which is the third key factor in improving decision-outcomes under conditions of uncertainty in the real world environment. Most failure stories can be largely ascribed to the lack of application of appropriate expertise in judgements. This paper questions the common industry practice of placing decision-making responsibility according to organizational hierarchy rather than expertise. In this first part of a continuing study, relying on two experiments, the paper illustrates two points. First, that decision-makers invariably superimpose their experience and expertise onto the results of normative tools and adjust them. This makes it imperative that they possess the requisite expertise. Secondly, we argue it is possible to develop a methodology to distinguish experts from intermediates and novices in the oil and gas industry. We assert that while years of experience help build expertise, by itself it is an unreliable indicator of the level of expertise.
Liquid Unloading in a Big Bore Completion: A Comparison Among Gas Lift, Intermittent Production, and Installation of Velocity String
Authors: Arachman Fitrah , Singh Kalwant , Forrest James K. , Purba Monas O. 
Published: December 2007

AbstractLiquid loading is a serious problem in low-pressure gas wells. Liquid accumulation in gas wells with inadequate energy to lift the liquid from the wellbore can cause a well to die prematurely.Various technologies are available to prevent liquid loading in gas wells. They include gas lift, intermittent production, and the installation of a velocity string. Each has applications and limitations for certain well and production conditions. Installation cost and operating cost are also important considerations in choosing the appropriate technology.This paper presents a comparison among these three different technologies applied to a low-pressure gas condensate well with big bore completion. At the early stage of production, a gas well with a big bore completion will allow high production rates (&gt; 100 MMscfd). As reservoir pressure declines, liquid hydrocarbons and water precipitate may cause liquid loading in the wellbore. Thus, it will require more effort to unload the well. Installing a velocity string will increase the gas velocity, which will prevent liquid loading. The optimum length, diameter and position will be determined based on calculated minimum gas velocity. Gas re-injection will be based on injection rate, and period, as well as method, through tubing or annular.This study focuses on showing the best solution to obtain optimum gas recovery from both a technical and economical viewpoint. This study uses published information from the Arun field as an example, but it is applicable to any low-pressure gas condensate field with a big bore completion.