bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recent Laboratory Results of THAI and Its Comparison with Other IOR Processes
Authors: Greaves M. , Xia T. X. , Turta A. T. , Ayasse C. 
Published: December 2007

Abstract
The integration of reservoir processes with horizontal well technology has led to the development of more efficient techniques for recovering heavy oil and tar sands bitumen. Whilst current in situ applications have concentrated primarily on steam injection processes, such as SAGD, new developments in air injection technology have been made using ‘Toe-to-Heel’ line drive. THAI – ‘Toe-to-Heel’ Air Injection, creates unique operating conditions in the reservoir, that have special advantages for heavy oil recovery.
The superiority of SAGD, compared with other steam processes, is manifested primarily in its gravity-assist mechanism, which allows a stable steam chamber to grow. The oil which is mobilised at the steam-oil interface drains down towards the horizontal producer well. In THAI, a similar gravity-assist mechanism exists by virtue of a ‘narrow mobile zone’ that develops immediately ahead of the combustion front. This occurs in a heavy oil reservoir when the vaporised oil and gases are prevented from communicating through the downstream oil zone and instead are forced to flow down into the exposed part of a horizontal producer well in line drive. The gravity-assist prevents gas override, ensuring an upright combustion front and hence stable process.
Semi-scaled 3-D combustion cell tests using heavy Wolf Lake oil have revealed the essential characteristics of THAI. Temperature profile measurements indicate that a ‘narrow mobile oil zone’ is formed, which allows hot vaporized oil, steam and combustion gases to be easily drained into the horizontal producer well. Cold oil in the downstream layer is effectively immobile due to its very high viscosity and consequently the oil saturation is maintained constant. This provides for constant, stable process conditions. The thermal sweep efficiency of the process is very high and virtually all of the oil in the zones contacted by the combustion front is produced, except for the small fraction consumed as fuel. The potential oil recovery is very high compared to other processes.
Mechanisms Causing Disproportionate Permeability in Porous Media Treated With Chromium Acetate/HPAAM Gels
Authors: Willhite G. P. , Zhu H. , Natarajan D. , McCool C. S. , Green D. W. 
Published: December 2007

Abstract
It is well established that treatment of porous rocks with gelled polymer systems often causes the permeability of water at residual oil saturation to be reduced by one to three orders of magnitude more than the permeability of oil at the water saturation that is immobile after treatment. This phenomenon is called disproportionate permeability reduction and is of interest because application of gel treatments in production wells has potential to reduce water production.
The mechanisms that cause this phenomenon are not well understood. This paper describes how permeability to oil and water is developed in pore space that is filled with a chromium acetate/HPPAM gel and why disproportionate permeability reduction is observed. Experimental data for the flow of oil and brine were obtained in unconsolidated sandpacks and in Berea sandstone cores with and without residual oil saturation after a chromium acetate/Alcoflood 935 gelant was injected and gelled in situ.
We show that oil permeability develops as oil penetrates into the gel-filled pore space, dehydrating the gel by displacing brine from the gel structure and creating "new flow" channels within the gel. The new pore space is a fraction of the original porosity, and the permeability to oil is reduced substantially from its initial value. Subsequent brine injection displaces oil from these flow channels but traps some of the oil in the new pore space as a residual saturation. The trapping of residual oil in the "new pore space" causes the disproportionate reduction in brine permeability because the brine flows primarily in the pore channels created by dehydration of the gel even though the gel has some brine permeability. When gelant is placed in matrix containing residual oil, dehydration of the gel reconnects some of the trapped oil and the oil permeability increases. Brine displacement experiments at the same pressure drop showed that initial brine permeability was reduced by factors of 1001000 more than the oil permeability, verifying the existence of disproportionate permeability reduction.
Laboratory Evaluation of Using Lignosulfonate and Surfactant Mixture in CO2 Flooding
Authors: Syahputra Andy Eka , Tsau Jyun-Syung , Grigg Reid B. 
Published: December 2007

Abstract
In a continuing effort to improve economics of oil recovery, the feasibility of using lignosulfonate with other surfactants for mobility control in CO2 flooding was evaluated. The laboratory tests were designed to quantify 1) the foam property of lignosulfonate with surfactant mixtures, and 2) the incremental oil recovery resulted from using such a mixture system.
The properties of foam were evaluated using a high-pressure foam durability apparatus in which the interfacial tension and stability of foam were determined. The mobility reduction of foam and the oil recovery efficiency were evaluated by conducting coreflooding experiments in a composite core, which contained well-defined high and low permeability regions in parallel to the flow direction.
Our results showed that lignosulfonate was compatible with most of the tested surfactants in generating high pressure CO2-foam. Lignosulfonate is a weak foam former by itself, however, it becomes a good foaming agent when mixed with other surfactant. Using such a mixture system in coreflooding experiments resulted in a significant improvement in oil recovery with a smaller amount of more expensive foaming agents and foam volume.
Compressibility Factor for Gas Condensates
Authors: Elsharkawy Adel M. , Hashem Yousef S. Kh. S. , Alikhan Abbas A. 
Published: December 2007

Abstract
Compressibility factor of natural gases is necessary in many petroleum engineering calculations. Some of these calculations are: evaluation of newly discovered formation, pressure drop from flow of gas through pipe, pressure gradient in gas wells, gas metering, gas compression, and processing. Typically, the gas compressibility factor is measured by laboratory experiments. These experiments are expensive and time consuming. Occasionally, experimental data became unavailable and the gas compressibility factor is estimated from correlations using gas composition or gas gravity.
This paper presents new methods for calculating the gas compressibility factors for the gas condensates at any temperature and pressure. The method is based on compositional analysis of 1200 compositions of gas condensates collected worldwide. When gas composition is known, this study presents a simple mixing rule to calculate the pseudo-critical properties of the gas condensate. The new mixing rule accounts for the presence of the heptane plus fraction. In case gas composition is unavailable, the study presents new gas gravity correlation to estimate pseudo-critical properties of the gas condensate. The study also presents evaluation of eight methods to characterized the plus fraction, three widely used mixing rules, and six methods to calculate the gas compressibility factor. Thus, this study presents evaluation of one-hundred forty-four possible methods of calculating the gas compressibility factor for gas condensates. Accuracy of the new mixing rule and the gas gravity correlation has been compared to other published methods. The comparison indicates that the proposed methods are consistent and provide accurate results.
Detailed Protocol for the Screening and Selection of Gas Storage Reservoirs
Authors: Bennion D. B. , Thomas F. B. , Ma T. , Imer D. 
Published: December 2007

Abstract
Gas storage reservoirs are used worldwide to store produced natural gas during periods of low demand for use during periods of high demand. These formations are often depleted natural gas reservoirs. Proper selection of a gas storage reservoir is important to allow proper and economic operation of the project on a long-term basis. This paper describes issues which need to be taken into consideration from a reservoir perspective when considering the development of a gas storage reservoir. These issues include the proper containment of the injected gas, maintaining injectivity and productivity over long-term operations, and problems which may be associated with the presence of free water or hydrocarbons in the storage reservoir (both mobile and immobile) as well as formation damage issues that often surround the drilling and completion of new wells in the gas storage reservoirs for development purposes.
Reservoir Characterization During Underbalanced Drilling: A New Model
Authors: Hunt James L. , Rester Stephen 
Published: December 2007

Abstract
The downhole pressure and rate data acquired during underbalanced (UB) drilling is essentially a well test during drilling. However, these data are rarely used quantitatively. Usually, the data are used qualitatively during drilling to make changes in the drilling design. In most UB drilling designs, the reservoir is considered to be independent of the well, providing fluid at an assumed constant rate. A reservoir model interacting with the well in real-time is needed.
Incorporating an appropriate reservoir model into the UB system results in a fully coupled system where changes in wellbore conditions are reflected in the flow rate from the reservoir. Data acquired from the UB process can then be analyzed to extract information about the reservoir, namely permeability versus depth, resulting in a more timely reservoir description.
We present a new solution of the mathematical model representing reservoir response during UB drilling. The UB drilling model is a modification of the mathematical model that describes the standard pressure transient test (the diffusivity equation). This modification, which makes obtaining the analytical solution more difficult, involves the time dependence of the boundary condition at the wellbore. As drilling progresses, the length of the wellbore increases and the fluid flow rate from the reservoir changes in response to the well length and wellbore conditions.
Several approximate solutions of this mathematical model exist in the literature. These solutions require simplifying assumptions such as no vertical permeability or the flow rate is a given function of time. In this study, a solution is obtained from the diffusivity equation with no further simplifying assumptions. Results obtained with the new analytical solution, with numerical simulations, and from the literature are shown to be comparable.
An actual field case is presented demonstrating the practical use of the model in a real-time UB drilling application.
Reducing Water Production in a Naturally Fractured Gas Well Using Sequential Gel/Gas Slug Injection
Authors: Wawro K. J. , Wassmuth F. R. , Smith J. E. 
Published: December 2007

Abstract
The application of gels for the control of excessive water production in oil and gas wells has been a treatment alternative for several years. The success of these treatments; however, has been relatively low. The Talisman Energy Inc. (Talisman)- operated Sukunka, British Columbia field pilot was conducted in conjunction with an ongoing research project at the Petroleum Recovery Institute to improve water abatement techniques in gas reservoirs. Sequentially injecting multiple slugs of gelant followed by gas allows for gel placement in the water conducting fractures or high permeability channels, while the gas overrides and reconnects to the upper gas zone.
A series of technical and economic screening criteria were developed to select suitable target gas wells with water channeling problems. Talisman's British Columbia candidate demonstrated water influx from a complex fracture system. The initial treatment design and sizing of the gel slugs was based on the experience gathered from previous gel applications in gas and oil wells. A high molecular weight polymer crosslinked with chromium acetate1,2 was used in the gelant formulation. In total, 127.5 m3 of gelant and 17,700 scm of nitrogen were injected during the sequential gel/gas slug application.
The gel application on this gas well was successful in several ways:
a relatively large treatment volume was successfully placed the water/gas ratio was significantly reduced incremental gas production paid for the treatment costs in 4 months
Identifying the nature of the water influx problem, and using the proper gel and placement technology lead to the success of this field application.
The Re-Engineering of Gas Storage Facilities to Meet the New Demands of Today's Marketplace
Authors: Evans L. Jay 
Published: December 2007

Abstract
The expansion of natural gas pipeline capacity from Canada, unbundling of LDC gas services, and projected increase in electrical demand across the United States is providing a unique opportunity for gas storage facilities to create value through new technology and innovative marketing techniques. Re-engineering of gas storage facilities by applying the latest technology and configuring the offered storage services to meet the new demands will significantly determine the value of these facilities. The paper will describe how these changes will impact the development of natural gas storage facilities, and how gas storage owners can position themselves to take advantage of these changes.
A Quick Method to Diagnose Flow Anisotropy Using Pressure Interference Data
Authors: Chen Her-Yuan , Hidayati Dewi Triarti , Teufel Lawrence W. 
Published: December 2007

Abstract
This paper describes a simple method to diagnose the existence of flow/permeability anisotropy using pressure interference data. The method is based on a log-log plot of pressure-change versus time/(distance)2. In addition, the well-pattern quadrant in which the orientation of flow/permeability anisotropy oriented can be identified within a range of 45 degrees, and the degree/contrast of anisotropy can be described qualitatively from the diagnosis plot. Examples based on simulated (analytical and numerical) and published field data are given to show the utility of the technique.
Field Case Study of Geomechanical Impact of Pressure Depletion in the Low-Permeability Cupiagua Gas-Condensate Reservoir
Authors: Giraldo Luis A. , Chen Her-Yuan , Teufel Lawrence W. 
Published: December 2007

Abstract
In-situ stress depletion is one of the primary causes of productivity reduction in low permeability reservoirs. Natural fractures not only enhanced the overall porosity and permeability of these reservoirs, but also increase the stress-sensitivity. Characterization of both pressure and stress fields, combined with well response analysis, is the first step in order to understand the behavior of such reservoirs.
This paper presents the study of stress-sensitive permeability in the near critical Cupiagua gas condensate reservoir in Colombia. The unusual tectonic stress regime σH &gt; σv &gt; σh combined with the evidence of natural fractures and the earthquake activity in the area make this an interesting case in looking for potential geomechanical impact on reservoir performance. A critical analysis of well tests coupled with the interpretation of core analysis, and numerical simulation is presented. Some practical recommendations trying to optimize reservoir management and final recovery are established.
Results suggest that permeability reduction not only is due to near well gas condensante effects but also associated with turbulent flow and in-situ stress depletion. Opening/closure of natural fractures is one potential mechanism to explain the stress sensitivity of productivity.
Liquid CO2 and Sand Stimulations in the Lewis Shale, San Juan Basin, New Mexico: A Case Study
Authors: Campbell S. M. , Fairchild N. R. , Arnold D. L. 
Published: December 2007

Abstract
In the spring of 1999, Burlington Resources initiated a well stimulation study in the Lewis Shale interval, San Juan Basin. The goal of the project was to establish the operational feasibility of pumping liquid CO2 and sand (Dry Frac) hydraulic fracture treatments1,2,3,4,5,6 in the Lewis Shale, and to compare production response of wells stimulated with liquid CO2 and sand to those stimulated with aqueous based systems. Production comparisons and well tests were used to quantify the results of the Dry Frac technology.
The Lewis Shale is present across the San Juan Basin and is part of the Mesaverde formation at approximately 4000'. Of the wells stimulated in 1999, 16 were treated with liquid CO2 and sand’ a water free stimulation technology. The remainder of the wells (46) were treated with nitrogen-foam water based fluids. Prior work completed within the Lewis interval suggests that imbibing gelled fluid into the low-permeability’ naturally fractured formation may cause permeability reductions. Permeability damage to the natural and hydraulic fractures may be eliminated and/or reduced by fracturing and propping the Lewis interval with the nonaqueous based fluids utilized in the Dry Frac process.
Formation Damage Processes Reducing Productivity of Low Permeability Gas Reservoirs
Authors: Bennion D. B. , Thomas F. B. , Ma T. 
Published: December 2007

Abstract
As drilling and completion technology advances, the trend to exploitation of gas reservoirs exhibiting ever lower permeabilities continues. This paper discusses issues associated with the identification of productive, low permeability, gas-producing formations and the successful completion and production of these reservoirs. For the purposes of this paper, a very low permeability gas reservoir is defined as a formation having an in-situ matrix permeability to gas of 0.5 mD or less. Criteria are presented for identifying economic absolute permeability cutoffs for low permeability gas-bearing formations. Very low permeability gas reservoirs are typically in a state of capillary undersaturation where the initial water (and sometimes oil) saturation is less than would be expected from conventional capillary mechanics for the pore system under consideration. These formations are commonly referred to as dehydrated or desiccated formations and have been documented on a worldwide basis. Retention of fluids (phase trapping) is discussed as one of the major mechanisms of reduced productivity, even in successfully fractured completions in these types of formations. As well, a variety of diagnostic and remedial treatment options are presented.
Sustainability Indicators and Metrics of Industrial Performance
Authors: Beaver Earl , Beloff Beth 
Published: December 2007

Abstract
There is a lack of accepted metrics and credible indicators to assess the current state of a company, an industry or the manufacturing sector of the economy with respect to its performance in promoting sustainable development. Metrics and indicators must be established before progress can be measured and goals for improvement can be set. These indicators of progress need to take into consideration material intensity, energy intensity, resource consumption and pollution dispersion, however, these measures alone are not sufficient indicators. They need to be assessed in the context of the total costs they represent to the company as well as in the context of an overall value-added the business generates.
The design and preliminary testing of indicators by companies under the auspices of the National Roundtable on the Environment and the Economy and the Center for Waste Reduction Technologies (CWRT) have yielded a good basis for establishing workable indicators of industrial performance along the themes of energy and material use, resource consumption and pollutant dispersion; however, these indicators have required refinement to ensure that they are simple, easily understood, reproducible, and cost-effective in terms of data collection and suitable for managerial decision making. In addition, work has been needed to adapt them from large to medium and smaller-sized companies.
Through a grant from US Department of Energy and under the auspices of CWRT, sustainability indicators and metrics in the areas of investigation described above have been further refined and adapted to become more robust for use in management decision making. As a part of this effort, a Total Cost Assessment tool has been developed, and particular focus has been placed on understanding social costs associated with environmental impacts as an indicator of future costs companies may bear.
Implementing a Contractor HSE Program in a New Overseas Operation
Authors: Davies Emily , Gilbert Anthony 
Published: December 2007

Abstract
"Implementing a Contractor HSE Program in a New Overseas Operation" describes the incorporation of Chevron's "Contractor HSE Program" into the business of the Venezuelan 3rd Round Reactivation Project LL-652. The LL-652 Field was previously operated by Lagoven, an affiliate of the Venezuelan national oil company, Petroleos de Venezuela S.A. or PDVSA. The field is now currently operated by Chevron on behalf of partners Statoil, Arco and EPIC (the "Consortium"). The paper details the issues surrounding the application of the Program in principle and in practice, outlining the type and scope of the operation to which the program is applied. The paper also describes how the program was incorporated into the Consortium contracting strategy and its’ application to all contracts. The paper summarizes: "lessons learned" after sixteen months of operation; the improvements achieved by the application of proactive performance measures as evidenced by personnel training; the application of safe systems of work and the improvement in contractor equipment and facilities; and the benefits of a sustained Contractor HSE Program to the Consortium, to the contractors and to the local community.
HSE-Management System in Action?
Authors: van Kuijk E. , Kuijper M. 
Published: December 2007

Abstract
Many Exploration and Production (EP) companies world-wide have made significant investments in setting up formal Health, Safety and Environmental management systems. The challenge is now to convert these investments into performance improvements. In this paper it is argued that a good "return on investment" will depend on: The level of integration with general business controls and management systems: more integration means more impact,The strength and quality of feedback loops: good feedback loops make the useful elements of a management system more effective and ensure timely removal of uncontrolled growth,The clarity of the longer-term vision: an HSE management system is a means to an end. Without a clearly defined "end" vision and policies, even the best HSE-MS may result in only marginal improvements and consequently disappointments.
The question "Is your HSE-MS in Action?" has to be answered negatively. In the end it is people, not Management Systems, who get into action. Which is why the clear longer- term vision is so important. Management systems alone do not motivate people to get into action. Motivation is created by building a shared vision on shared values and by translating this into a concrete strategy and goals.