bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Oil Recovery in Malaysia: Making it a Reality
Authors: Hamdan M. K. , Darman N. , Hussain D. , Ibrahim Z. 
Published: December 2007

Abstract
A considerable amount of hydrocarbon resource is estimated to remain in the ground even after primary and secondary recoveries in the fields. As of 2003, the estimated oil-in-place from the forty-seven producing fields in Malaysia stand at about 20.1 BSTB, with a cumulative production of 4.9 BSTB and reserves of 2.5 BSTB1. This translates to an averaged recovery factor of only 36.8 percent for producing fields in Malaysia. For this reason, the remaining oil-in-place of 12.7 BSTB i.e. 63.2% of STOIIP will be the prime target for Enhanced Oil Recovery (EOR) projects. On top of the value that could be gained through EOR applications, most of the fields are already entering maturing stage for primary and/or secondary depletion with declining oil rates and increasing water-cut and GOR trend. This situation will further merit the application of EOR processes. However, to date, there has been no full-field application of EOR in Malaysia, with the exception of a pilot WAG project in Dulang field2,3 and MEOR stimulation project in Bokor field4–6.
In 2000, a screening study on seventy-two (72) reservoirs in Malaysia has identified almost a billion barrels of additional reserves that can be achieved through EOR. Majority of these potentials resides in a few major reservoirs, which carries about 60% of the total EOR potential7. The screening study has also identified several key EOR technologies that are most applicable in Malaysia, namely gas injection, chemical injection, and microbial. Thermal processes were investigated but have been ruled out due to the operational, properties of reservoir fluid, safety and commercial limitation of the methods for Malaysian offshore applications. However, transforming those potentials into real projects may face some challenges and change of operating philosophy. Factors such as facilities condition, sources of injection gas, reservoir characterization, technology applicability, and commercial aspects will play an important role in planning for an EOR projects in Malaysia.
This paper presents the possible opportunities that could be realized by EOR applications, and discusses issues and challenges including change of mindsets required in making EOR a reality in Malaysia.
Emission Characteristics of a Modified CNG Gasoline-Cycle Engine
Authors: Kalam M. A. , Masjuki H. H. , Amalina M. A. , Abdesselam H. , Mahlia T. M. I. , Aslam M. U. 
Published: December 2007

Abstract
This paper presents the experimental results carried out to evaluate the exhaust emissions and performance evaluation of a computer integrated bi-fuel spark ignition engine that has been retrofitted for two fuels namely compressed natural gas (CNG) and base fuel gasoline, operations under steady state with lean burn condition. The used engine was a Proton Magma 4-cylinders spark ignition engine. The emission results such as CO, HC and NOx were measured and compared between the above two fuels. A locally produced three way catalytic converter (TWC) consisting of platinum (Pt), palladium (Pd), cerium oxide (CeO2) and rhodium (Rh) was used to assess the emissions. The CeO2 was used in TWC as an oxygen storage capacity (OSC) to enhance the oxidation process for CO and HC oxidations.
Application of Empirical Data in Forecasting Water Flood Behavior
Authors: Schauer P.E. 
Published: December 2007

Abstract
The use of empirical data to validate injection predictions and to prepare oil production forecasts is described. Histories of typical inputs show that reasonably reliable injection predictions can be made from equations based on Darcy's Law. The production performance of five Illinois floods is presented in a graph of accumulated increased recovery versus accumulated water injection per acre-ft, thereby permitting comparisons and forecast independently of time and input rate. The various steps used to apply this empirical data to a forecast are described, beginning with the method of estimating the accumulated injection necessary to achieve first production increase. Flood performance indicates this to be a function of permeability heterogeneity. The forecast of subsequent behavior is shown to consist of selecting the most appropriate empirical curve to use as a guide, with its selection based on relative reserves and degree of confinement. The introduction of time and rate is described as a stepwise integration of the accumulated production versus injection curve at the forecast injection rate.
Computerized Pressure Transient Data Analysis for Vertically Fractured Tight Gas Wells
Authors: Sinha Mihir K. , Padqett Larry R. 
Published: December 2007

ABSTRACT
A procedure for analyzing short-term transient pressure (well test) data for a vertically fractured gas well is presented. The analysis provides unique estimates of important reservoir, well bore and fracture parameters by simulation and matching test data. The parameters developed can then be used to forecast the performance. The simulator is primarily designed around analytical techniques, utilizing published dimensionless pressure drop functions for a vertically fractured well system1,2–4 as well as for wellbore storage effects.16 By using this procedure practicing engineers will considerably lessen time and resources involved in analyzing well tests, while obtaining more reliable interpretations.
The procedure is designed to consider the entire range of the available drawdown and buildup data while minimizing user intervention. The model considers the effects of fracture conductivity, fracture length, fracture face damage, formation flow capacity or permeability, wellbore storage, fracture storage, and variable rates of flow during the test period, as well as the effect of producing time on the buildup behavior.
Several examples of actual field test data and their analysis using this procedure are presented. It is cautioned that the method finds best application when a single pressure drawdown followed by a buildup is available for a simple, homogeneous and uniform reservoir geometry. Furthermore, the well should be cleaned of fracturing fluids and a stabilized static pressure must be obtained prior to conducting the flow test. Finally, single phase gas flow should occur both in the reservoir and the wellbore for any meaningful analysis of the data to be possible.
Electrochemical Analysis of Surfactants for Microemulsion Flooding
Authors: Becker Michael C. , Glover Charles J. , Darby Ron , White Ralph E. 
Published: December 2007

ABSTRACT
A previously reported indirect Polarographie method gave fair analytical results over a wide range of concentrations of SDBS in solutions containing NaCl or hexane. A modification of the method allowed analysis of the surfactant in the presence of isopropanol, although with somewhat reduced accuracy. The method performed well for an alkyl-ortho-xylene sulfonate.
Economic Appraisal of Thermal Drive Projects – A New Approach
Authors: Williams Richard L. , Brown Susan L. , Ramey Henry J. 
Published: December 2007

ABSTRACT
Because of rapid increases in oil prices, oil companies have begun to re-evaluate recovery projects that were once considered economically unattractive. High on the list of new investment opportunities are thermal oil recovery projects. The combination of price increases, investment incentives (such as tax credits and subsidies by the Federal government), and proven superior recovery performance over other enhanced oil recovery methods has made many thermal recovery projects appear economically attractive.
To evaluate a thermal recovery project; reservoir, production, and economic parameters must either be known or assumed. Many numerical models have been developed to simulate existing projects and match actual production data. However, these models are often unduly complex and employ assumptions which reduce their applicability to a particular reservoir. Also, computer time and costs may prohibit an in-depth study of a reservoir.
Because thermal recovery projects require a substantial capital investment, a detailed reservoir and economic analysis is imperative in order to optimize oil production and revenue, maximize profits, and attain a good rate of return on investment. This paper presents a method to facilitate the estimation of oil recovery by either continuous steam injection or in-situ combustion, and generate a cash flow estimate based on the production schedule of each process.
It is assumed that the reservoir parameters are known, or can be obtained from conventional logging and laboratory methods. A synthesis of heat and mass balance equations presented in the literature is used to estimate oil production. A discounted cash flow is generated based on a probability distribution of the oil price, fuel price, capital costs, and operating costs. Discounted net present worth is graphed against the injection rate of steam or compressed air, and an optimal injection rate can be determined.
This method was developed to allow management to decide whether steam injection or in-situ combustion will be the most economically attractive process in the field. Parameters such as injection rates, pattern size and type, and efficiency may be changed either to describe a particular field application or to optimize the production schedule of a heavy oil recovery project. Application of this model to existing projects shows that for different parameters, either in-situ combustion or continuous steam injection will be the more economically attractive in the field.
Comparative Analysis of Pump-Off Control Systems for Field Applications
Authors: Amezcua Joe D. 
Published: December 2007

ABSTRACT
One of the most controversial subjects related to the production of reservoir fluids is the application, field acceptance, and reliability of automatic pump-off control (POC) devices to rod pumped wells. Pump-off controllers made by three manufacturers were selected for an extensive evaluation in the McElroy field. Results indicate that the controllers do offer an economical means of operating rod pumped wells and that field acceptance is attainable.
Corrosion Monitoring on Rod-Pumped Wells Using Linear Polarization Probes
Authors: Shehorn L. Steve 
Published: December 2007

ABSTRACT
Linear polarization instantaneous corrosion rate probes have been successfully used to optimize corrosion inhibitor treatments on producing oil wells, utilizing a wellhead bypass loop which allows water separation and collection when readings are to be taken. Well failures and corrosion inhibitor costs have been reduced simultaneously with linear polarization monitoring in two of Shell Oil Company's most corrosive fields in the Permian Basin of West Texas and New Mexico.
Success Story To Produce 200 MMscfd of Gas From Mutiara
Authors: Prihartono Y. A. , Riksa A. P. , Affan S. R. 
Published: December 2007

Abstract
Mutiara Field is one of four fields in VICO Indonesia, East Kalimantan that located in southern of the contract area. The central processing plant of Mutiara Field is originally designed for processing 165 MMscfd gas. In 2002–2003, some planned work programs were done successfully that include 5 well workover, installation of additional one MP compression unit and 2 well drilling program. The success of these work programs became apparent that Mutiara could produce more than 165 MMscfd. However, the plant throughput was limited by flare system capacity and gas dehydration capacity. So, the challenge was to overcome the capacity limit at minimum cost to allow Mutiara to increase sales gas export.
Some inter-multidisciplinary studies were conducted to solve the problem, to find the most suitable and most economic solution. The study concluded that there are two options to process gas more than plant capacity limit that are: installing additional flare system or to modify plant's overpressure protection system. The last option was selected based on time and cost justification. This modification is to cease incoming gas to the plant in order to maintain gas inside the plant below the flare capacity in case of overpressure occurred in the event of process upset.
Other problem that exists is limitation of dehydration unit to absorb water in the gas until the allowable limit. Overhaul dehydration unit had been done to improve its performance. This was also to include clean up and pressure testing of all equipment associated. Also, some pipeline debottlenecking projects at outlet plant were done to reduce plant outlet pressure that also supports operation of the plant.
The above changes were made at almost no capital cost, allowed Mutiara to produced gas at 200 MMscfd started on mid of 2003.
CO2 Injection in Carbonates
Authors: Izgec O. , Demiral B. , Bertin H. , Akin S. 
Published: December 2007

AbstractStarted as an EOR technique to produce oil, injection of carbon dioxide which is essentially a greenhouse gas is becoming more and more important. Although there are a number of mathematical modeling studies, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to characterize relevant chemical reactions associated with injection and storage of CO2 in carbonate formations. Porosity changes along the core plugs and the corresponding permeability changes are reported for differing CO2 injection rates and with differing salt concentrations. CT monitored experiments are designed to model fast near wellbore flow and slow reservoir flows. It was observed that permeability initially increased and decreased for slow injection cases. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. The experiments were modeled using a commercial simulator where solution and deposition of calcite were considered by means of chemical reactions. The calibrated model was then used to analyze field scale injections. It was observed that solubility storage of CO2 is larger compared to mineral trapping.
Downhole Deployment Valve – Case History
Authors: Timms A. , Muir K. , Wuest C. 
Published: December 2007

Abstract
During Underbalanced Drilling (UBD) a dilemma arises over which practice to use whenever the drill string has to be tripped out of the hole. Options are to kill the well, which may cause formation damage and defeat the object of UBD, to use a snubbing unit, or to trip with a live well, both of which have serious safety and cost implications. Setting a packer which is subsequently pushed down the hole on re-entry has been attempted on several occasions with varying degrees of success, but can only be used for completion operations and not for routine bit trips.
The Downhole Deployment Valve (DDV) was developed specifically to address this issue and provides the capability to close off the well at depth, allowing the wellbore above to be de-pressurised and thereby greatly facilitating tripping operations. When the DDV is closed, reservoir pressure reaches balance point below the valve, but the wellbore above is vented, which eliminates the "pipe light" condition completely and removes the need for snubbing. The DDV is a full-bore casing valve, hydraulically controlled from surface via control lines; it is run with the casing and can be cemented in place.
Analysis of Pore Throat Size and Use of the Waxman-Smits Equation to Determine OOIP in Spindle Field, Colorado
Authors: Kolodzie Stanley 
Published: December 2007

ABSTRACT
This paper describes the development of a method used to define pay and calculate OOIP in the Spindle Field. Traditional methods of calculation do not yield reliable results for pay or OOIP due to the shaly sand nature of the reservoir rock. The Spindle Field contains more than 1,150 wells and covers parts of seven townships in northeast Colorado (Figure 1).
In this study, a minimum pore throat size of 0.5 microns was selected as a pay cut off. Methods were developed to estimate from logs the porosity and permeability data necessary for input into an equation to calculate pore throat size. Water saturations were calculated using a form of the Waxman-Smits equation. Cation exchange capacity values were estimated from the SP log for input into the Waxman-Smits equation. The net pay intervals were combined with the results of the Waxman-Smits equation to give values of hydrocarbon pore thickness (HCPT) in individual wells. The HCPT values of the field wells were spotted on a map and a volumetric analysis made to give an OOIP figure.
Confirmation of the pay definition was made by the correlation between calculated HCPT and ultimate primary recovery of twenty individual wells. Confirmation of the OOIP calculation results was made by the nearness of the OOIP calculated using this method to an OOIP estimate made from ultimate primary recovery of the Amoco wells in the field.
Insert String Technique Reviving Idle Wells
Authors: Sulai A. T. , Hassan Y. 
Published: December 2007

Abstract
Low reservoir pressure is the major contributor to low production in Temana field that cause some of high water cut wells to quit production. The existing gas lift system is not effective due to low liquid level in the tubing resulting in the wells keep on circulating the lift gas. A simple technology called "insert string" was applied to address this problem.
Temana field consist of shallow and intermediate reservoirs, with depths ranging from 1800 ft to 4000 ft. The intermediate reservoirs are mostly solution gas drive and reservoir pressure depleted drastically causing more wells to quit production. The shallow reservoirs are combination of water and solution gas drive dominated by the latter with low reservoir pressure ranging from 600 to 1,100 psig. However when the water cut increases, liquid level in the tubing drops and causing the well to quit production.
The first insert string was installed in April 2002 with the main objective to stabilize production by adding one more gas lift injection point below the last existing gas lift mandrel. Following the success of the first job, several additional insert strings were installed to revive the idle wells. In conclusion, the insert string is a very practical, low risk and low cost technology that effectively improves productivity from low pressure wells and successfully reactivates the idle wells. This paper highlights the successful application of the technology and the lesson learned.
Using Economic and Production Evaluation Methodologies to Expedite Commercialization of Intelligent and Multilateral Wells
Authors: Ramos X. , Anderson A. , Sakowski S. A. , Hogg C. 
Published: December 2007

Abstract
Despite potential and proven benefits, intelligent and multilateral wells have yet to achieve the greater-than-fifty-percent adoption level that would qualify them as truly commercialized technologies. The prevailing perception is that while these technologies hold significant potential to reduce costs in high-end, niche applications, they are too high-tech and high-risk to justify for middle- and low-end applications. The reality is that economic and production benefits exist across all types of applications, but proving it has posed a challenge.
Technology champions cite potential value drivers for intelligent and multilateral wells, including reducing drilling cost, minimizing intervention expense, optimizing production and enhancing recovery. Cost reduction is a tangible benefit that can be easily estimated to justify an installation and easily recorded to measure its success. However, estimating production enhancements and incremental reserves is more demanding and has thus far been underused to evaluate these technologies.
This paper will present a number of cases in which the value of both intelligent and multilateral wells has been estimated using conventional production and reservoir engineering techniques. The paper will explain how nodal analysis and reservoir simulation techniques have been applied to evaluate and compare wellbore and reservoir performance for conventional versus intelligent wells. The authors will also show how economic cases for such advanced completions can be built on the foundation of these analyses.
Improving the Closing Characteristics of Subsurface Safety Valve with Combined FEA and CFD Modeling/Numerical Analysis
Authors: Li L. J. , Zhang H. , Davis G. R. , Kalb F. D. , Hamid S. 
Published: December 2007

AbstractSurface-Controlled Subsurface Safety Valves (SCSSVs) are designed to automatically shut-in a well below the earth's surface in the event of damage to the wellhead or other key components of a completion string. Flow rates in highly productive gas wells can produce stresses that exceed the design limits of a typical subsurface safety valve during closure in blowout conditions. High-rate uncontrolled flow conditions can act to prevent a SCSSV from closing or can subject the valve to stresses that the valve cannot withstand. Flow tests conducted to verify valve performance under certain flow conditions are often not capable of predicting valve performance when the valves are subjected to flow conditions different from the test conditions. Because the net force on the flapper is a function of the flow parameters, a valve that tests successfully at one set of conditions is not guaranteed to perform successfully in a different set of conditions.This paper will discuss the use of Finite Element Analysis (FEA) combined with Computational Fluid Dynamics (CFD) to economically and effectively determine 1) if a SCSSV will close under various flow conditions, and 2) whether it will withstand the associated forces generated during the closure. If this method is used, the flow tests could then be used to verify the accuracy and confirm results of the FEA and CFD analyses. After the FEA/CFD models are validated through flow testing, the performance of the valve in response to changes within the flow parameters or safety valve configuration can then be predicted using FEA/CFD models. Actual testing can be performed only to confirm the results of FEA/CFD or may be avoided completely.