bluuebunny/crossref_metadata_2025_split huggingface dataset:
First of Kind Self Erecting Tender Rig Combines Performance and Safety
Authors: Krueger Philip J. , Leland Anders 
Published: December 2007

Abstract
The drilling of minimum cost development wells in the Gulf of Thailand (GOT) requires a drilling philosophy based on continuous improvement. Adherance to this philosophy has yielded some of the fastest drilling times in the world. This performance is due in part to the ability to plan and drill 12 to 16 well platforms instead of "one-off" wells, a concept that has been fundamental to building efficiency. To rig up on a platform ready to drill 16 wells requires a great deal of teamwork and up-front planning between the asset teams and the drilling group. To drill minimumn cost wells, key contractors and service companies must be aligned with the common goal of efficient and safe operations. Drilling rigs, tools, and equipment are constantly being upgraded and redesigned to be fit for purpose to the conditions encountered in the GOT.
In 2001 Smedvig's Self Erecting Tender Rig (SETR) T-7 was at the end of a five year contract with Unocal Thailand. The T-7 had been under continuous contract in the Gulf of Thailand since it was first commissioned in 1981 and was scheduled for dry docking as part of the ABS classification process. Unocal and Smedvig saw an opportunity to evaluate upgrades to the barge and derrick set (DES) with the goal of improving drilling efficiency and HES performance. It was believed that the best way to work more efficiently while maintaining a safe working environment was to evaluate the drilling unit and make improvements there. A team was then formed to evaluate the drilling unit and the economics of investing capital in the upgrades.
This paper describes:
Description of geographical setting Performance drilling history Project conception and overview Operating company and rig contractor relationship Rig modifications purposes and performance Health Environment and Safety concerns and management
A Novel Method of Assessment of Spurt and Filtrate Related Formation Damage Potential of Drilling and Drilling-in Fluids
Authors: Amanullah Md. 
Published: December 2007

Abstract
Solids as well as the liquid phases of drilling muds invade and interact with reservoir formations that contain oil and gas. These invasion and interactions change the formation permeability and in extreme cases may stop the fluid flow from the reservoir to the wellbore. The damage caused by mud spurt and drilling mud filtrate can influence the log response significantly due to the change in near borehole permeability and displacement of formation fluids by the mud filtrate. This dictates the assessment of the spurt and filtrate related formation damage potential of drilling muds and drill-in fluids to screen and select the best fluid for drilling the reservoir section of the borehole. This paper describes a novel method to highlight the formation damage potential of drilling muds by assessing the erosional characteristics of mudcakes formed by different mud systems.
A unique test procedure and a novel test facility have been developed for experimental determination of mud spurt and filtrate related formation damage potential of different muds and drill-in fluids. The test set up consists of a wooden bridge to fix the mud agitator, an erosion cell for closed loop circulation of eroding fluid, a mud agitator to simulate the hydrodynamic condition of the borehole-drill collar annular section, a lab jack to elevate the erosion cell to a desired height to maintain a constant clearance between the borehole wall (filter paper) and the extreme end of the rotating shaft.
Experimental results indicate significant variations in the erosion coefficients of mudcakes for an identical hydrodynamic condition and clearance between the borehole wall and the end point of a rotating shaft. Cakes formed by several water-based muds were evaluated using the newly developed technique. The results indicate that the presence of electrolyte increases the erosion coefficient of bentonite mudcake and thus significantly increases the damaging potential of bentonite mud. Ionic fluid loss additives such as PAC and CMC reduced the erosion behaviour of salt water-based bentonite mudcake and thus indicate their ability to reduce the spurt and filtrate related formation damage. The presence of non-ionic fluid loss additive ‘modified starch’ shows little improvement of erosional behaviour of salt water-based mudcake and thus indicates severe formation damage potential if the reservoir section is drilled using this type of drilling muds.
Application of Downhole Oil-Water Separation: A Feasibility Study
Authors: Alhoni Mohamed A. , Jerbi Khalid K. , Drawil Taher A. , Zekri Abdulrazag Y. 
Published: December 2007

Abstract
An engineering feasibility study has been conducted on the major operated oil field of waha oil company to determine the feasibility of applying downhole oil/water separation technology (DHOWS) and to rank candidate wells within this field on the basis of their suitability for a DHOWS instalilations. Under operations consistent with the existing field development (or any future developments), the nature of the GE reservoir is such that, the remaining oil reserves will have to be produced at high and constantly increasing watercuts. Downhole separation and disposal of produced water represents a material opportunity to improve the current and future operations of the field.
A screening template was developed to review the reservoir and well characteristics in more details and to identify a list of candidate wells for the possible implementation of DHOWS technology. Several operational risk and concerns exists in respect of the candidate wells were identified. Eighteen wells our of twenty four wells demonstrated favourable reservoir and well characteristics and meet the initial DHOWS screening criteria. The screening template may be used to evaluate other fields for potential conventional DHOWS applications. A preliminary design of a DHOWS application for three wells is presented in this paper.
Innovative Planning and Monitoring Improves Production from an India Offshore Field
Authors: Kumar Adesh , Gupta V. P. 
Published: December 2007

Abstract
Mumbai High field discovered in the year 1974, is located in Western Offshore of India, 160 km South West off Mumbai City. The field was put on production in May 1976. The field achieved a peak production of about 400,000 BOPD during year 1984. To maintain reservoir pressure, suitable water injection scheme was put in place in 1984-85. The field is currently operating on gas lift mode of artificial lift. The field is in now matured stage.
There is a vast gap in demand and supply of hydrocarbons in India. Country import about 66% of its crude oil requirements. Current high rise in prices of crude oil necessitated increased efforts by National Oil Company (ONGC) to enhance production by about 0.5 MMT from the committed targets. Indian offshore being the 70% contributor of domestic crude oil, special focus was accorded to these fields.
Mumbai High being largest field in Offshore, a systematic planning and monitoring of action plan were adhered. To augment the production from this matured field, as a short-term measure, a multi-disciplinary team (MDT) was formed. The team brought out the action plan in August-2000 and implementation started in September-2000. The four types of jobs were planned for Bombay High field viz. Drilling of new development wells, diversion of existing well location to new location by long-drift side-track (LDST), cost effective innovative stimulation jobs, additional perforations in some of the existing producers. All these four types of jobs were carried out within the available resources like drilling rig, stimulation vessel and marine survey unit (MSU). The systematic monitoring of these actions has led to a learning curve for future. In addition to this, some of the wells were taken up for other remedial jobs like surface modifications to reduce backpressure in some well platforms, work-over jobs, scale removal jobs etc. By close monitoring of each well and associated action, the planned additional targets of 0.5 MMT up to March-2001 were achieved.
The present paper describes the details of new development wells drilled using non-damaging drilling mud, diversion of existing well location to new location using the existing slot using LDST, innovative stimulation technique and additional perforations. For each of these activities, a detailed analysis has been made and learning curve drawn for future.
Numerical Modelling of Stress Around a Wellbore
Authors: Chatterjee R. , Mukhopadhyay M. 
Published: December 2007

Abstract
Numerical analyses are carried out to obtain the understanding of stress distribution near and around a drilled circular wellbore into the rock masses. The seven numerical two-dimensional models are generated using the ANSYS finite element software. The models are analysed to investigate the effects of the equal and differential far-field stresses on and around the drilled wellbore, to study the contrast in Young's modulus for rocks inside and outside the welbore as well as to study the effects of fluid pressure during drilling. Stress magnitudes and orientation is varying uniformly around the wellbore under the equal far-field stresses. Differential far-field stresses are the main cause of deformation of stress trajectories. Stress trajectories become elliptical around the wellbore. Differential far-field stresses and contrast in rock strength parameter like, Young's modulus are playing important role in modifying the stress contour pattern near and around the wellbore. The drilling fluid pressures along with the differential far-field stresses affect the change in stress inside as well as outside the wellbore.
Corrosion Management in Production Pipeline Network Using Risk Management Analysis
Authors: Kusumo A. Lesto Prabhancana , Supriyatman Deden , Kristanto Dedy , Prasetia Andi Eka 
Published: December 2007

Abstract
Corrosion management is the integrated corrosion handling, begin with design of facilities, material selection/composition of metal, manufacturing, transportation, installation, operational, monitoring, maintenance and treatment if the specific incident. Risks will happen in early design until maintenance and will resist operation system performance and function. Risk management analysis is a new concept to make planning of operation system that integrated from design, operational until maintenance. This concept integrates Hazard Operability (HAZOP), Fault Tree Analysis, Failure Modes and Effect Analysis, Failure Modes and Effect Critically Analysis, Risk Based Inspection, Risk Centered Maintenance, Risk Based Maintenance and many more. The international standards (such as API, API-STEP, EPA, ISO 9000, ISO 1400, AISI, NACE) completed the integration. Risk management analysis is the part of Integrated Asset Management System (IAMS) that have developed recently in PERTAMINA/PSC/JOB in Indonesia. Corrosion handling using risk management analysis is applicator in production pipeline network of oil and gas industry. Using risk management in corrosion management will get output: make optimal in operation system, minimum effects to personnel and environment, keep equipment quality and performances, also cost efficiency.
A New Method for Evaluating Stimulation Treatments in Carbonate Reservoirs of Saudi Arabia
Authors: Al Qahtani Abdullah M. 
Published: December 2007

Abstract
Acid stimulation treatment has been conducted to restore/improve productivity/injectivity of wells completed in carbonate reservoirs. A Well is generally put on stimulation treatment schedule if a transient pressure test shows a positive formation skin factor. From a production engineering viewpoint, the success of an acid treatment is measured by the magnitude of production rate improvement. Another important factor is the stimulation cost for the amount of production gain. Viewed as such, candidate selection for stimulation plays an important role in the success of a stimulation treatment.
This paper presents a new approach of evaluating stimulation jobs in carbonate reservoirs in Saudi Arabia. A new Type–curve approach is presented to assess the success of a stimulation job in a specific field. This study is supported by analytical and simulated solutions in addition to field statistics. Case studies of success and failures stimulation treatments are presented.
The paper also highlights the economic consideration in stimulation treatments that can influence stimulation decisions.
Successful Extreme Underbalance Perforation In Exploration Well, Donggi Gas Field, Sulawesi
Authors: Halim Andry , Danardatu Heru 
Published: December 2007

Abstract
Donggi Structure is one of the gas field prospected in Banggai Basin, Central Sulawesi. Donggi-1 (DNG-1), which is the first well drill in this field, was drilled in August 14, 2001 and was reached TD at 2498.5 m. The drilling in this well has been successfully done without any major problem and it is + 2 day finished ahead of drilling prediction/program.
Donggi gas field is commonly composed of Carbonate reef (limestone). The lithology of this field sequence from surface down to basement is : Celebes Molase, followed by POH formation (clay with sandstone), Mentawa member (reef of limestone), Minahaki formation (limestone) and Tomori formation (limestone).
To prove the gas prone seeing from logging evaluation after drilling, TCP gun was run by using "Extreme Underbalance Perforation" technique to perforate the well completed with the DST assembly. The gun system is a mechanical release that secures the guns firmly during perforation and avoiding the risk of fishing the tool after the operation. The well is flowing immediately after the perforation which will allow immediate well clean up. Therefore, the well productivity will increase and formation damage will be minimized. In EUB perforation, it is created more than 1000's psi drawdown instead of less than 100's psi in classical perforation.
The EUB application in this well has been successfully flown the gas and condensate during the test and reduced the skin effect and increase the reservoir productivity. It can be seen from the DST-4 and DST-5 analysis result that the skin factor is negative.
The isochronal and pressure build up analysis result in zone-4 is Pr = 2560 Psia, AOFP = 25.1 MMSCFD, skin factor is −1.88 and the radius of investigation is 206 m, and in zone-5 is : Pr = 2540 Psia, skin factor is −4.42, and the radius of investigation is 1593 m.
A New Method for Determination of Gas Reservoir Parameters with Rate Decline Data
Authors: Li M. , Sun L. T. , Li S. L. 
Published: December 2007

Abstract
For the boundary-dominated flow in a gas reservoir producing against constant wellbore pressure, Fraim proved that normalized time VS. rate data traces Arps exponential decline curve. However, it is tiresome to match type-curve when normalized time is introduced. To obtain normalized time, G, a value for original gas in place, is assumed and is then used to calculate normalized time and to match the curve with the Arps’ base b curve closest to the exponential curve. A new value of G is worked out. This process will be repeated several times until convergence is obtained for the exponential decline curve.
Technique developed in this paper provides a rapid and accurate way to analyze rate decline data. Normalized time VS. rate data follows the exponential decline curve, indicating non-linear regression technique can be applied to tackle the problem. Regression technique is used to obtain the exponential decline parameters Di and qi based on which reservoir parameters deteremined with Fraim's technique can be easily derived from formulas presented in the paper. The put technique matches Arps' exponential curve automatically and determines reservoir parameters without type-curve matching . The validation and procedure of the present technique with rate decline data from Fraim's literature is also described in the paper.
Chemically Enhanced Production – Managing Waxy Condensate
Authors: M Zaini Khairul Nizam , Othman Mohamad , Yunus A. Rahman 
Published: December 2007

Abstract
Waxy condensate was suspected as a contributing factor to the process and operational upsets at one gas-condensate processing platform operated by Petronas Carigali. As an immediate solution, the suspected wells were either shut-in or curtail back, while a detail investigative study is conducted.
The main objectives of the study are to identify the source and quantify the extent of the problem and subsequently formulate appropriate solutions to manage the problem. Key actions implemented include in-situ condensate testing, gas process profiling and extensive laboratory analysis of condensate samples from all producing gas wells in the field. However, the difficulty is to identify the contributing wells due to the nature of the light condensate i.e. high API gravity of condensate, but low pour point as contrast to typical waxy crude where the API gravity is generally low. While wax precipitation from crude has been extensively studied, precipitation from gas condensates is not generally well recognized1.
From the various laboratory analysis data, it was confirmed that paraffinic wax would form at the current operating temperature of the gas-condensate plant. Furthermore, from well analysis data, four wells were confirmed as the potential source of the problem.
Through wax crystal modifiers2 or Pour Point Depressant (PPD) screening and testing using condensate sample from one of the shorlisted well, a suitable chemical was identified for plant testing on two shorlisted wells. A pilot test using the PPD was conducted on-site and the condensate pour point was monitored at both the offshore processing platform and the onshore gas terminal (OGT). Subsequently the performance monitoring data showed that the PPD is able to reduce the pour point of the condensate to an acceptable level. The optimum dosage of PPD treatment was also determined. This encouraging result permitted both wells to produce at their maximum potential.
Experimental Studies on Injecting Wastewater to Improve the Recovery of Abandon Condensate Gas Reservoir
Authors: Ping Guo , Cheng Yuanzhong , Liu Liping , Du Jianfen , Hong Li , Liu Jianyi , Li Shilun , Chang Su 
Published: December 2007

Abstract
It is traditionally considered in China that recovery of condensate gas reservoir cannot be improved by water injection. But, recently work abroad showed that it could be greatly improved by water injection. To address whether the recovery may be improved by water injection, a series of experiments are performed based on the preliminary PVT test. The experiments employed about 1m long-core and compound condensate fluid obtained from Ban 2 Group abandon condensate gas reservoir of DaGang oil field, CNPC. The studies include three main parts: (1) depleting the condensate reservoir to abandon pressure 8Mpa at different velocity to study on the rate effect of recovery. (2) Injecting water into core after pressure reach abandon pressure (3) increasing the pressure to 20MPa by water injection and then keep injection and production balance to study on further condensate and gas recovery. The study showed that condensate recovery measured in PVT cell is half of that tested in long-core, the result is concordant with the practical conditions; exploration by keeping injection and production balance under abandon pressure can further increased condensate recovery by 3.39% and gas recovery by 10.11% and condensate recovery increase with the increase of water injection velocity; balance production under recovered pressure can further increased condensate recovery by 0.68% and natural gas recovery by 5.39%. In-situ test showed that after re-injecting 135×104m3 wastewater into abandon condensate gas reservoir, further 8006t condensate oil and 4885 × 104m3 natural gas were produced to Oct. 2002. The study highlights good economy profits as well as environmental friendly by water injection.
Microbial Prevention of Wax Precipitation in Crude Oil by Biodegradation Mechanism
Authors: Sadeghazad Ayoub , Ghaemi Nasser 
Published: December 2007

AbstractOne of the most severe problems at any oil fields producing paraffinic oils is wax/paraffin deposition. The microbial treatment that based on the activity of the naturally occurring, selectively isolated bacteria is a proved effective alternative method to the conventional methods to prevent and remove wax deposition. This article discusses the screening and evaluation of bacterial strains on the effect of biodegradation on the heavy paraffinic hydrocarbon components (C16+), especially normal alkanes.The experimental results of cloud point temperature measurements show that as the apparent molecular weight of crude oil (solution) decreases, its cloud point temperature also decreases. So that, wax precipitation will be delayed. Therefore, microbial biodegradation of heavy paraffinic hydrocarbon components, especially normal alkanes, will be one of the most effective methods to prevent wax precipitation and deposition. Three bacteria strains and four different consortia of them were used through the experiments. The three strains were Bacillus subtillis, Bacillus licheniformis, and Pseudomonas aeruginosa.Gas chromatography, infrared spectroscopy (IR), and NMR analysis were performed on the samples before and after microbial treatments. Also, the physical properties of samples were measured before and after treatments. Based on the physical characteristics of samples and on the results of their special analysis, the Pseudomonas aeruginosa strain was highly effective in the degradation of normal alkanes between C16-C25 and Bacillus licheniformis was highly effective in the degradation of cyclo- and iso-alkanes between C20-C30. In contrast, Bacillus subtillis had no or less effect on the degradation of heavy paraffinic hydrocarbons. Where as, through out the literature, Bacillus subtillis was introduced as one of the effective microorganisms in the biodegradation of heavy paraffinic hydrocarbon components.
Performance Prediction of a Well under Multiphase Flow Conditions
Authors: Marhaendrajana T. , Ariadji T. , Permadi A. K. 
Published: December 2007

Abstract
This paper presents an analytical method to predict production performance of a well producing from a solution gas-drive reservoir. Many available analytical techniques published for a solution gas-drive reservoir have been intended mainly for data analysis techniques and they were proved to be valid only for one particular flow regime (i.e., transient flow).
Many have used Inflow Performance Relationship (IPR) method to predict the well performance in these reservoirs. The shortcoming of this method is that it is based on regression to either field data or numerical simulation results. The data are sampled on one particular flow regime (i.e., boundary-dominated or pseudo-steady state flow). Hence, the outcomes are highly dependent on the condition at which the data are sampled.
The analytical method in this paper addresses all flow regimes (transient, transition, and boundary dominated flow). The solution also considers that all phases (oil, gas, and water) can flow. This solution is also validated with results from numerical simulation for various fluids and reservoir properties.