bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Feasibility of Using Time-Lapse 3D Seismic to Monitor Fluid Displacements in an Abu Dhabi Onshore Oil Field
Authors: Kleiss Erik , Melville Peter , Al-Jeelani Abu Baker 
Published: December 2007

Abstract
Time-lapse or '4D' seismic has been used to directly monitor the fluid movements in some oil- and gas-reservoirs. This technique allows one to verify and where necessary to update the reservoir flow models, e.g. to incorporate 'geological surprises' like unexpected flow barriers or conduits. The method is based on the change of the acoustic properties (velocity, density) of the reservoir when the initial reservoir fluid in place (oil, gas, brine) is replaced by others while the reservoir is produced. Under favourable conditions this change in properties leads to a detectable change in the seismic reflection.
Successes of 4D seismic have been reported, mostly from clastic reservoirs located offshore and onshore heavy-oil/tar sands reservoirs. In such reservoirs the change in seismic response with changes in reservoir fluid is relatively large. Direct hydrocarbon indicators, AVO and bright spots often work well in these reservoir types. Furthermore the good quality of modern 3D marine seismic data allows one to reliably detect these changes in many offshore cases.
For the large onshore oil fields produced by ADCO, the situation is more challenging. The main reservoirs are formed by fairly hard carbonates; they are reasonably deep and consist of several thin zones with quite different flow properties due to variable porosity, permeability and fracturing. The surface is covered by sand dunes, which severely hamper the recording of high quality recorded seismic data. Some oil fields have been producing for more than 30 years and have been penetrated by several hundreds of wells, including infill horizontal drilling. However, the reservoir behaviour is still not fully predictable and sometimes wells do not perform as expected. With extensive use of water-injection for production support and gas-injection programs scheduled, a further calibration and refinement of the reservoir models would be quite welcome. The recent improvements in the quality of 3D seismic data seen in Abu Dhabi could enable the successful application of 4D seismic (and its associated benefits) for these fields.
Simultaneous Gravel Packing and Filter Cake Removal in Horizontal Wells Applying Shunt Tubes and Novel Carrier and Breaker Fluid
Authors: Saldungaray Pedro M. , Troncoso Juan C. , Santoso Bambang T. 
Published: December 2007

Abstract
Gravel packing long horizontal sections is an exceptional challenge in itself due to the lengths now being completed. When simultaneous gravel packing and effective mud cake removal is considered, the complexity of the process is compound, posing a more demanding challenge to the completion process. Previously, to gravel pack a horizontal well it was necessary to seal off the wellbore from the formation to such an extent that substantial circulation could be maintained during gravel packing. This implied the need of a filter cake in place that needed to be removed in a separate treatment after the gravel packing operation to achieve an efficient completion. The introduction of screens with shunt tubes eliminates the need for well circulation during the gravel packing operation, and therefore simultaneous removal of the filter cake while gravel packing becomes a viable possibility.
In this paper we present an integrated approach to gravel packing and removal of the drill-in fluid filter cake. This was achieved by a combined application of a surfactant based carrier fluid in an enzyme and chelant breaker solution using shunt tubes for open-hole gravel packing. The shunt tubes ensure complete packing by allowing an alternate path for bypassing sand bridges that may form in the screen and formation annulus, due to excessive leak off. The carrier-breaker fluid ensures contact of the breaker with the filter cake in the entire interval during and after gravel packing.
Clean up efficiency tests, fluid rheological behavior and fluid design are presented together with field case histories. These case histories demonstrate that gravel pack placement and well productivity index have been improved with respect to previous practices, while simultaneously reducing overall completion cost.
Upheaval Buckling of Gas Injection Pipelines Onshore Abu Dhabi - A Case Study
Authors: Saadawi Hisham 
Published: December 2007

Abstract
Upheaval buckling is a potentially serious problem for buried pipelines operating at high temperatures and pressures. In recent years, this problem has been receiving wide attention in the oil industry. Most of the published literature deals with offshore applications in the North Sea. The problem of upheaval buckling, however, is not limited to offshore pipelines operating in a cold climate, but can also affect onshore pipelines in a desert environment.
Shortly after commissioning a major gas project onshore Abu Dhabi, some sections of the injection gas pipelines protruded through the trench and the soil cover. Extensive investigations were carried out to analyze the problem, identify the causes and remedy the situation. This paper describes a case study of the problem of upheaval buckling of high pressure gas pipelines in a desert environment.
A New Correlation for Gas-condensate Dewpoint Pressure Prediction
Authors: Humoud A. A. , Al-Marhoun M. A. 
Published: December 2007

Abstract
The paper presents a new empirical correlation to predict the dewpoint pressure of gas-condensate fluids from readily available field data. The new correlation relates the dewpoint pressure of a gas-condensate fluid directly to its reservoir temperature, pseudoreduced pressure and temperature, primary separator gas-oil ratio, the primary separator pressure and temperature, and relative densities of separator gas and heptanes-plus fraction. The correlation was developed based on field and laboratory PVT analysis data of several gas-condensate fluid samples representing different gas reservoirs in the Middle East. Additional data sets, not included in the development of this correlation, were used to validate the new model’s accuracy. Based on the error statistical analysis results, the new model outperforms the existing correlations.
Geological Modelling: Backbone in Developing A Mature Oil Field (Jorang Field Case)
Authors: Kurniawan Kurniawan , Syaefuddin Asep , Bailey Terry , Santoso Hendro Hari 
Published: December 2007

Abstract
Maximizing production from a mature oil field is a current and future CaltexPacific Indonesia (CPI) challenge. Developing a good geological model, thefirst stage of the process, helps visualize the location of potential remainingoil reserves and identify new drilling opportunities. A development package of3 Horizontal and 2 vertical wells that accommodated a trade-off between riskand opportunity was made to develop these potential areas of remaining oilreserves. Numerous challenges, such as the accuracy of structure prediction andreal time well re-design, occurred during the execution of the developmentplan.
This paper shares some of the experiences, software tools, and bestpractices used to identify hydrocarbon potential, to design well paths beforeand while drilling, and to develop economic scenarios for monitoring theexecution of the drilling program.
Noise Induced Health Risk Assessment & Mitigation Measures Thereof At Gas Compression Stations
Authors: Bose C. , Acharya A. K. 
Published: December 2007

Abstract
The paper deals with noise induced health risk assessment study in Gas Compressor Stations (GCSs) where sound level varies between 85 to 105 dBA. On routine audiometry test survey on 200 employees working in GCSs, approximately 6% of them were found to have been affected due to noise induced illness. Thereafter a joint team comprising experts from HSE cell and labour union representatives carried out survey of 19 such stations, identified the root causes and suggested remedial measures (both technical and administrative decisions). The entire case study was a unique approach of participation of Labour Union in Management to resolve HSE related problem.
Formation Fines Stabilization Using Surface Adsorption Polymerization: Field Application of an Emerging Technology
Authors: Saldungaray Pedro M. , Caretta Fausto , Sofyan Muhammad 
Published: December 2007

Abstract
Wells in a field offshore South East Sumatra, Indonesia, produce oil at very high rates and water cut. Under these conditions the reservoir is susceptible to fines migration with the associated pore plugging and production decline. Conventional acid treatments to dissolve fines in the near well bore have been effective for limited periods. However after some days or weeks of production, rates have been observed to fall as fines once again migrate, accumulate and plug the formation and gravel pack. Retarded mud acid formulations -that claim fines stabilization- have also been put into practice in an attempt to solve the problem. These formulations have also been ineffective and fines migration remained an unsolved problem.
A novel technique to inhibit fines migration through the "Surface Adsorption Polymerization" technique has been used to stabilize the fines around the borehole. The technique is a three-stage process that results in fines being coated with a solid thin polymer film that is stable at high flow (shear) rate locking the fines in place. The validity of the approach has been confirmed with flow tests in cores from the field under study, and has been validated by field results. This paper presents the process followed to implement this technique in the field, case histories and production data of the treated wells.
Experience with the Quantification of Subsurface Uncertainties
Authors: Charles T. , Guemene J. M. , Corre B. , Vincent G. , Dubrule O. 
Published: December 2007

Abstract
Now that tools are available for building 3D earth models, and for quantifying uncertainties on parameters associated with the earth model, it is much easier to understand the impact of all subsurface uncertainties on field production. In the last years, we have accumulated a significant experience and know-how addressing this sort of issues in integrated studies.
We briefly recall how we address the problems, what tools and methodologies are used for quantifying the joint impact of subsurface uncertainties. We discuss the key points in a study : clearly stressing which operational decision will be supported by the uncertainty study.reformulating the problem in terms of an uncertainty study workflow.listing the key subsurface uncertainties impacting the study.translating these key uncertainties into uncertainties on gross-rock volume, oil-in-place or reserves, using the workflow.
Then we illustrate the approach with four field cases. The first example highlights how the joint impact of geometrical, geological and dynamic uncertainties on reserves estimates can be quantified. The second example focusses on the impact of fault sealing on a development decision for an HP-HT field. The third example shows how uncertainty figures can be used to help optimally locate an appraisal well. The last example illustrates how the quantification of structural uncertainties can be used to justify the acquisition or processing of seismic data. We also discuss how new uncertainty quantifications techniques are impacting some of the standard industry workflows. For instance : –scenario approaches can now be run in conjunction with probabilistic approaches.–rather than defining three mini, median and maxi geological models, we prefer to define these models in relation with quantitative parameters of interest, such as OIP and Reserves.
We also stress that all our approach merely consists of translating uncertainties on input parameters into uncertainties on parameters of economic interest. The quality of the result obtained depends on the validity of quantified uncertainties on input parameters.
Water Rise Tracking and Prediction
Authors: Febvre F. , Moinard L. 
Published: December 2007

Abstract
This paper presents two different and simple methods of tracking water rise in a gas reservoir. From the case study of a complex multi-layered sand reservoir of Indonesia, it shows how the two independent approaches were validated, and generalised to other similar reservoirs. The objective is to control the water production, thus extending the life of reservoirs with an active aquifer.
The first method is based on material balance coupled with 3D mapping. The paper shows how water influx which is initially calculated from history match of the material balance, can then be converted into water rise. This approach can be easily implemented on a spreadsheet with some basic input from the geological maps of the reservoir, without the need for any heavy 3D reservoir simulation. Once water rise is calculated, the paper goes on to describe how it can simply be predicted.
The second method is based on reservoir saturation logging. The paper details step by step, the procedure that was elaborated to get direct in situ measurement that could be exploitable despite a complex environment in an ageing field. It describes how the combination of different recorded parameters can reduce the uncertainty from the raw measurement. It also highlights recommendation that were drawn from initial unsuccessful attempts to log through two strings of pipe.
This paper shows how these two methods were validated on the same reservoir when a new well was drilled and tagged the new water contact at the predicted depth.
Post Mortem of a Fast Track Subsea Oil Development
Authors: Guise David R. , Chered Norma Fitri 
Published: December 2007

Abstract
Jangkar-1X was drilled in the first quarter of 1998 and discovered oil and gas in five reservoirs in the Lower Gabus and Pasir Formations. The Jangkar Field is located in the Kakap PSC (Indonesia) and is part of the Wrench Fault Trend which has yielded significant rewards to the Kakap PSC partners. The well was not tested but open hole log evaluation, down hole fluid samples and pressure data confirmed the presence of oil and gas in highly porous and permeable sands. In response to this success, a fast track development plan was formulated which resulted in a second well, Jangkar-2X being drilled, completed and placed on production as a sub-sea oil producer prior to the end of 1998. This fast track development was the result of a strategic decision to pre-purchase the long delivery items required for sub-sea tie-ins in anticipation of a least one successful exploration well in a multi-well drilling program. This paper reviews the basis for the decision to pre-order inventory and documents the strategy and development plan which resulted in this well being placed on production within ten months of the field being discovered as well as the technical and commercial results of the project.
Cost and Risk Reduction Through Innovation: Remotely Actuated Completion Equipment for Deepwater and Extended Reach Wells
Authors: King James 
Published: December 2007

Abstract
Eliminating intervention during well completion reduces operating expense and risk. In deepwater, horizontal and extended-reach applications, remote actuation systems for setting completion tools are reducing well intervention and completion time without compromising reliability or safety. This paper will detail the operation of two commercially successful technologies that permit remote actuation. This paper will also examine the reduction of risk and rig time expense through the use of remote actuation systems and outline the selection process for determining the correct technology for a given application.
Preventive Maintenance of Electric Submersible Pumps and its Relationship to Root Cause of Failure Analysis
Authors: Limanowka W. A. , Degen S. , Benwell G. 
Published: December 2007

Abstract
We live in working environments where it is difficult if not career limiting, to say "no" to job assignments from bosses and colleagues. Pulling before catastrophic failure is normally not done, except in rare instances. Units are rarely pulled until total electrical failure occurs and the unit will not restart. Many times these restart attempts, after the systems have gone to ground, destroys the evidence needed to determine the reason for failure.
Proper diagnostics of a unit that shuts down on overload could, in many instances, reduce repair costs for the unit, provided they are pulled prior to restarting. However, this is not the general procedure in the field. Many lease operators do not have the equipment or training to troubleshoot ESP systems after they have gone down and, being pressured for production will automatically attempt a restart as soon as they discover the failure.
Producing wells can be monitored, and corrections in operation such as incoming power, wellhead pressure, casing pressure, etc., can reduce the stresses and increase the life of an ESP system. Also, use of proper monitoring techniques can aid in determining needs for replacing equipment and can reduce the repair costs if units are pulled and/or resized prior to catastrophic failure. The operator is the most important determining factor on run-life and is probably the least trained in the operating and design limitations of ESP systems. Further improvement in RCFA in the ESP field is undoubtedly in the hands of the ESP users. More manufacturer-user RCFA teams working together are becoming necessary to extend ESP run times.
The objective of this paper is to provide modifications to Root Cause Failures Analysis (RCFA) methods, specific to ESP applications and show how many of the methods can be applied as Preventive Maintenance in the ESP field. It will be supported by case study from the Meekwap field where the "Time between Failures" (TBF) was tripled as a result of close cooperation between field operator and ESP manufacturer.
Long Stroke Pumping Systems in Deep Well Applications – Field Study
Authors: McCannell Deana , Holden Derek R. 
Published: December 2007

Abstract
This paper compares and illustrates the effectiveness of a unique reciprocating rod artificial lift system as applied to Gulf Canada Resources in the Swan Hills area of Northwest Alberta, Canada. The applicable wells produce between 280bbls/day and 695bbls/day of high water cut fluid from depths ranging from 7200ft to 9500ft.
The system used includes a long stroke-pumping unit, high strength continuous rod, and a big bore-tubing pump. The unique features of the components within the system have proven to reduce production costs by improving failure rate and other associated operating costs.
In order to determine the benefits of this unique pumping system, the direct well pulling expenses and limitations for the concerned wells will be compared to the other lift systems used in the field.
Recommended Practices for Slim-Hole Steam Injectors
Authors: Castrup Suzanne Griston 
Published: December 2007

Abstract
Single-string and multi-string slim-hole completions have become popular in recent years as an inexpensive means of injecting steam into shallow, low pressure sands. While slim-hole injectors appear to be simpler and cheaper to drill and complete, wellbore heat losses can be excessive at low injection rates. In addition, if a good bond is not achieved during primary cementing, thermal stresses, incurred once steam is injected, increase the likelihood of tubing failure and steam channeling behind pipe. Therefore, an appropriate tubing size and weight must be used to prevent well failures.
For example, initial slim-hole steam injectors completed with 2-3/8 inch and 2-7/8 inch tubing are no longer advisable because of insufficient mechanical integrity. Similarly, poor cement bond in triple-string slim-hole injectors has resulted in a high percentage of well failures. Consequently, the costs associated with tubing deformation, poor steam containment, and high wellbore heat losses cannot be ignored when considering slim-hole injectors for a steamflood project.
This paper discusses current drilling and completion practices and addresses the benefits and risks associated with slim-hole steam injectors. The short-term economics of initial low drilling and completion costs are compared to the long-term economics of efficient steam placement to target sands using single-string and multi-string slim-hole injectors. Recommended practices and guidelines are presented for proper, cost-effective application of slim-hole injectors to improve steamflood performance.
Developments and Application of a Four-Parameter Instrument Withstanding High Temperature of Heavy-oil Thermal Recovery
Authors: Dai Peiwen , Wang Zuoqing , Wu Guowei , Zhang Yi 
Published: December 2007

Abstract
A new method is presented in this paper, which is used to measure four-parameters, namely down-hole pressure, temperature, flow rate and steam quality, on thermal recovery for heavy oil. Throttling action of the instrument itself and down-hole vortex shedding sensors combine to measure both flow rate and steam quality. According this method, an instrument has been developed which makes use of steel wires to go up and down, metal heat-insulating bottles to insulate heat, a down-hole SCM to gather and store data, a host computer on the ground to redisplay and deal with the results. Calibrations indoor and applications on the spots prove that the measuring errors of pressure and temperature are less than 0.5%, mean square root errors of flow rate and steam quality less than 6%. It can meet the expectations of the thermal recovery testing for heavy oil.
The Use of a Simulation Model to Optimize Reservoir Management in a Very Mature 24Z Reservoir, Elk Hills, California
Authors: Estremadoyro Julio G. 
Published: December 2007

Abstract
The 24Z Reservoir is a very mature field located on the western nose of the 29R anticline in the Elk Hills Field (Figs. 1,2 and 3). It has already produced almost 50% of its OOIP therefore, any additional development potential appears very limited. A comprehensive reservoir study was begun in late 1999 with a new geological and petrophysical interpretation to generate an improved reservoir description. As part of this reservoir study, a simulation model was also prepared. The purpose of this model was to better understand and improve the performance of this reservoir; to assist in evaluating any additional development potential and to compare alternative operating policies in formulating an optimized depletion strategy. The results of this simulation model indicate that there is enough potential to justify additional infill development wells. The reactivation of some shut-in down-dip wells and a blowdown of the gas cap were also evaluated.
Extending Downhole Pump Life Using New Technology
Authors: Muth G. M. , Walker T. M. 
Published: December 2007

Abstract
Sand, whether formation sand or frac sand, is produced along with hydrocarbons and water from many wells. This sand can accelerate wear of the plunger and pump barrel, and can also cause the plunger to stick in the barrel. These problems may result in frequent pulling jobs and expensive pump repair costs. The Farr plunger, a newly designed pump plunger and pull rod, has been tested during this past year in numerous oil fields in California. These tests indicate that the Farr plunger has the potential to reduce the pump wear and plunger sticking problems caused by sand production. This paper describes this new design, and the initial results of the field trials.