bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Application of an Inline Separation Technology in a Real Wet Gas Field
Authors: Hamoud Amir A. , Boudi Adnan , Al-Qahtani Saeed D. 
Published: June 2009

Abstract
The inline separation technology has attracted the attention of oil and gas field operators due to the considerable weight, space and cost savings that can be achieved. In addition, the inline separation technology can play a major role in de-bottlenecking and upgrading the existing production facilities.
Several gas wells are beginning to produce significant water. Older gas plant facilities were not designed to handle high water production. Compact inline separation technology has the potential of eliminating any water-related restriction on well production, and reducing the investment for upgrading existing conventional separators.
A trial test of a skid-mounted inline separation technology (Deliquidizer) is being implemented at a wet gas remote header. The header has three flowing wet gas wells. The separated gas and liquid (water and condensate) streams will be monitored for flow rate and phase fractions using suitable multiphase flow meters. The separated gas will be flowed to the gas plant and separated liquids will be flowed in a separate flowline to the nearest oil processing facility. This will allow unrestricted flow of the gas wells without the need to upgrade the water handling facilities of the gas plant resulting in significant cost savings.
This paper discusses the concept, objectives and benefits of inline separation technology application in Saudi Aramco wet gas field. The field trial test loop, process conditions, equipment specifications, and future applications of this technology within Saudi Aramco will also be discussed.
Improved Performance of Downhole Active Inflow Control Valves through Enhanced Design: Case Study
Authors: Al Mubarak Saeed M. , Sunbul Ahmed H. , Hembling Drew , Sukkestad Tor , Jacob Suresh 
Published: June 2009

Abstract
Saudi Aramco has completed more than 100 multilateral wells with intelligent completions to monitor and control the inflow from the laterals in realtime without well intervention. The intelligent completion typically consists of isolation packers, multi-position downhole valves and downhole gauges. Field data has confirmed that the systems are functional in controlling inflow from laterals and that the flow characteristics of the downhole valves are varied due to different completion design and productivity index of producing zones. A field review was initiated to optimize the operation of the existing wells and to design a standardized valve design that suits different well completions and reservoirs.
This paper illustrates a case study detailing comprehensive analysis of downhole valves performance and design. It presents the process used to improve downhole valve design based on field data. The new design provides higher level of control at lower flow rates, hence enables finer adjustment of distribution of inflow among different laterals or segments. The modeling work is based on a new operating envelope so that inflow control valves can be used to produce rates that satisfy both reservoir management strategy and well production scheme. The modified insert chokes has been flow tested and installed in recent wells' completions. These wells will be flow tested to evaluate the performance of the new downhole control valves.
Evaluation of the Bitumen Intervals in a Carbonate Reservoir, Case Study in Abu Dhabi onshore field, UAE
Authors: Haggag Mostafa , Al-Yaaqoobi Amena 
Published: June 2009

Abstract
The field under study is an anticline carbonate reservoir onshore Abu Dhabi, UAE. It produces from Lower Cretaceous Reservoir. The integration of core data, log data and laboratory chemical analyses highlighted the presence of bitumen at the base of the reservoir in many wells. The bitumen has a negative impact on reservoir performance; it acts as a permeability barrier for production and injection, and also reduces effective porosity; i.e. affects both flowing and storage capacities of the field. Moreover, it reduces the recoverable oil from the field.
This paper discusses the methodology used to evaluate the bitumen in the reservoir in terms of the occurrence in the wells, the thickness, and the distribution across the field. It suggests the structure evolution of the bitumen to help in tracing it in non cored wells and also to define the bitumen intervals in new wells. The paper also highlights the technique used to incorporate the results in the 3D reservoir model.
Implementation of the results allows better understanding of the reservoir performance due to the presence of bitumen intervals and enhances the reservoir history match of the 3D reservoir model. The results are currently used as inputs in several ongoing full field reservoir studies such as PVT, and wax & asphalting scale deposit studies.
Comparison of 3D VSP and High Resolution Surface Seismic Images for Improved Reservoir Monitoring and Characterization
Authors: Mueller K. , Soroka W. L. , Baloushi M. N Al , Jeelani O. S. Al , Paulsson B. , Chavarria A. 
Published: June 2009

Abstract
Two 126 level 3-component 3D-VSP's (Vertical Seismic Profiles) were acquired coincident with a high-resolution surface seismic survey. Figure 1 shows the location of the first 3D-VSP on the crest of the field and the second 3D-VSP on the flank of the field. Using the surface seismic sources, 11712 shot points were used per VSP to collect 4.5 million traces per VSP, which produced a 6-9 km² final 3D-VSP image around each of the two wells. Due to the large offsets and high density of traces available it was possible to experiment with acquisition and processing methodologies to produce images that resolve thinner beds, see more structural definition and improve reservoir characterization. Results from the first phase of processing are very encouraging and show the 3D-VSP images to be able to resolve subtle faults that were not seen in older surface seismic data and have higher frequency content than the new 640 fold, high resolution surface seismic data. Source and receiver decimation tests are aiding in efforts to better understand how to acquire high quality 3D-VSP's in the future with minimal effort and cost. Efforts to expand the size of the 3D-VSP volumes around the wells have been successful. The largest image produced so far has been able to image more than 1.5 km away from the wellbore. The high quality VSP images and the fact that VSP's can be repeated at much lower cost than surface seismic makes this technology very attractive for future time-lapse reservoir monitoring studies.
Assets Remote Monitoring GIS System
Authors: Tarabzouni Thamer , Al-Harbi Lafi , Al-Moaibed Ehab , Kaabi Abdulaziz 
Published: June 2009

Abstract
Oil and gas companies possess thousands of remotely installed assets that are critical and deemed necessary to ensure the safety and integrity of their vast operations. This fact necessitates extensive periodic field inspection trips to check asset status and operating condition. Consequently, maintenance trips are planned and executed to fix or calibrate those assets on a regular basis. Clearly this process involves many challenges, including the lack of knowledge of the assets' true operating condition and their operational effect until the next scheduled inspection visit. Also, it is difficult to determining asset locations in the field, when and why they stopped functioning, and the potential risk as a result of these failures.
Integrating a Geographic Information System (GIS) with remote asset monitoring technologies provides an innovative solution to address many of these concerns. This application will display the real-time status of these scattered assets to ensure maintaining the safety and integrity of the companies operations. The system provides visual, SMS, and e-mail alerts to report immediately any abnormal situations. The GIS provides the user with a representation of how these assets are installed geographically to unify and facilitate location and navigation tasks based on Location Based Systems (LBS) devices. GIS also allows a "Spatial" analysis to group together maintenance and inspection activities, based on priorities and geographical boundaries. This result will lead to resource optimizations (both in NDE and manpower), improve efficiency and integrity of assets, and enhance the safety of both field crews and the overall operation.
3D OBC Seismic Survey Parameters Optimization for a Carbonate Field Offshore Abu Dhabi, United Arab Emirates
Authors: Ishiyama Tomohide , Painter Derrick , Belaid Kamel , Ikawa Hidemasa , Al-Suwaidi Ahmad S. , Karwatowski Joe , Barwick David , Kaneko Mitsuyoshi 
Published: June 2009

Abstract
There is no doubt that 3D seismic data make a powerful contribution to field development. Less obvious, and often controversial, is the critical step of defining level of seismic survey effort required to achieve the objectives for field development. An over-specified seismic survey could be costly, and an under-specified seismic survey would not achieve the objectives.
A 3D OBC pilot seismic survey was conducted in a carbonate field of offshore Abu Dhabi, United Arab Emirates with the main objectives: (1) to demonstrate imaging of the Upper Jurassic Arab formation; and (2) to optimize survey parameters for future seismic surveys. In this highly-specified pilot seismic survey, two orthogonal 3D datasets were acquired, and one swath 3D dataset was simulated by sampling shot-points parallel to receiver-lines. The data density is significantly different among these datasets, however the offset and azimuth distributions are similar. Twenty-three cubes were generated from these datasets by decimating the full data. Unless particular reasons necessitated change, the same processing parameters were applied to all cubes to minimize any differences due to processing effects. The relationship between data quality and operational effort was determined by analyzing twenty-three cubes qualitatively and quantitatively from the structure interpretability point of view.
The main findings are: (1) higher specification cubes successfully imaged the main Upper Jurassic Arab reflectors; (2) higher specification cubes require higher operational effort; (3) in general, higher specifications improve data quality; (4) however, data quality eventually reaches a plateau even with increasing specifications; and (5) certain cubes are more efficient, they provide higher data quality with lower operational effort.
The methodology and results will be used to assist in establishing and optimizing survey parameters for future seismic surveys offshore Abu Dhabi, United Arab Emirates.
The Application of High Integrity Protection Systems to Prevent Topside Overpressure which Caused by Water Injection
Authors: Wang Jinfeng , Lili Wang , Yonghao Li , Yueping Zhuo 
Published: June 2009

Abstract
The Tang South-East platform is unmanned and a combined wellhead and process platform in the North Sea, it was installed to produce and separate the well streams into a vapour phase and a liquid phase, and transfer the gas and liquid in two separate pipelines to another field. There was no automatic relief system or flare system on the Tang South-East platform, and the High Integrity Protection Systems (HIPPS) was built to protect the export gas and liquid pipelines.
When water injection is applied later in Tang South-East field, it will lead to possible overpressure for the topside process systems under the situation of direct water hit through fracture.
Our solutions to prevent this overpressure can be divided into two parts:
First, design new HIPPS. Three transmitters and one Emergency Shut Down Valve (ESDV) are proposed to build downstream of each manifold, working with the other items, including Emergency Shut Down (ESD) and Independent Emergency Shut Down (IESD) panels, Master Control Valves (MCV) and Wing Control Valves (WCV). A reliability study is carried out; the resulting unavailability of the HIPPS is 9.716 × 10-5, which meets the requirement of better performance than a standard relief valve which has an unavailability of 2.12×10-4.
Second, change the process system upstream of ESDV according to new design pressure. This paper shows how to define this new design pressure which is higher than original design pressure.
HIPPS are chosen in this project basically because they offer lower install cost of flowlines and process systems, and they do not discharge to the environment.
HSE Management in a Drilling Environment
Authors: May Andrew , Moonen Alain , Logan Stewart , Allinson Jackie 
Published: June 2009

Abstract
Since the commencement of the Pearl GTL drilling activities in Qatar's North Field in 2004, five drilling rigs have been taken on contract and, to date, it has been a 4-year, 3 million man-hours LTI free operation.
Recognizing the challenges of an overheated industry, introducing large numbers of inexperienced staff on the drilling rigs, proactive HSE management by engaging ALL levels of the operator and contractors' organizations has resulted in top quartile HSE and operational performance.
The HSE management starts at the inception of the project and is part of the tendering process. From the moment the contracts are awarded HSE engagement sessions are utilized to align expectations and generate a road map of deliverables as per the Upstream (Well Engineering) HSE Management System (HSE MS).
The success of a "One Team" approach to HSE management is through leadership commitment, i.e. displayed by fully supporting the assignment of resources. In the preparation phase this is reflected in ‘hazardous exposure reducing’ investments, Off-site HSE induction sessions with all crews and management, ‘STOP for safety’ sessions and continuous HSE support in creating HSE cases (Rig Specific/SIMOPS).
Providing joint support in the execution phase for implementing and further optimizing HSE tools with the crews who are actually executing the job, has led to a deeper understanding and buy-in. Examples of tools utilized are Hazard Identification Bow Tie Development, Toolbox Risk Identification Cards (TRIC) as a supplement to the widely used Job safety Analysis (JSA) and STOP reporting with participation rewarding.
Challenges of Optimizing Oil Recovery of "Tight Carbonate" Reservoir, Onshore Abu Dhabi Oil Field, United Arab Emirates
Authors: Benlacheheb Mohamed , Edris Adib , Al Jeelani Omar Sultan , Al Marzouqi Salman Hassan , Al Sheehi Maryam , Al Hashemi T.A. 
Published: June 2009

Abstract
Production rates from tight reservoirs are marginal. However, the tight carbonate reservoir under study accounts for a significant percentage of STOIP, which is the key for drilling and producing these reservoirs. The challenges here are to optimize both the production rates and the total amount of the recovered oil. Good understanding and high quality reservoir characterization lead to efficient reservoir management plans.
The studied reservoir is over 50 ft thick and covers an area of 140 km2 with porosity ranges from 3 to 25 pu. This reservoir was deposited during a transgressive cycle on a broad and relatively shallow shelf in an open to slightly restricted subtidal marine environment. The depositional environment plays the major role as well as the diagenitic overprint in term of low reservoir quality. The reservoir is subdivided into four sub zones separated by stylolites. The reservoir can be divided into two main facies fining upward. Although the lower facies composed of Algal Skeletal Floatstone-Boundstone while the upper one is Foraminifera Wackestone, the reservoir quality is relatively low in both (permeability does not exceed 6 mD) due to the severe impact of digenesis. Although a production test conducted over this reservoir reached only 300bopd dry oil, it is still encouraging to implement a sound development plan in order to sustain a reasonable plateau and obtain an optimum recovery. Moreover, the reservoir structure is quite complex in term of isolation with the overburden dense formation and juxtaposition with lower reservoirs. Several options are considered to develop this tight reservoir, but basically they consider the use of long horizontals under WAG and Gas injection processes.

Introduction
As the industry seeks to increasingly exploit reserves of oil contained in low permeability reservoirs, the reservoir under study present an average permeability of 1 mD. Many questions have been raised about how to optimize production rate, the total amount of the recovered oil and the optimum practice to drill and complete this kind of reservoir. The effective stimulation technique to obtain economic production rate is another issue. The reservoir damages during the drilling operations and workover also represent a concern.

Geological background
The structure of the reservoir is characterized by a highly faulted elongated NE-SW anticline with a main axis length around 25km and a width of approximately 6km covering an area of 140km2. fig.1
The structure was formed during the Upper Cretaceous in response to the compressional event related to the main ophiolites obduction. Subsequent movement of the structure during the Tertiary has occurred due to the Zagros orogene event which has regionally tilted the area down the NNE.
Cyclic Water Injection Improves Oil Production in Carbonate Reservoir
Authors: Surguchev Leonid , Giske Nils Harald , Kollbotn Lars , Shchipanov Anton 
Published: June 2009

Abstract
The cyclic injection process to improve water flooding in carbonate reservoir was evaluated in laboratory experiments, as well as analytical and numerical simulations.
Laboratory cyclic injection experiments were performed on a carbonate rock sample with an artificial horizontal fissure. Live oil was established by in-situ recombination of dead oil with hydrocarbon gas at reservoir temperature and bubble point pressure. The experiments were designed by numerical simulation of the cyclic process. Analytical modelling was done to evaluate cyclic injection sensitivity to critical reservoir and process parameters.
The cyclic water injection experiments above oil bubble point pressure increased oil recovery by additional 2.9% of Oil Originally In Place (OOIP) above ordinary water flood. This effect can be attributed to the hasten imbibition of water into the matrix during pressurisation half-cycles and capillary retained water in the fine pores in the matrix resulting in oil counter current flow from matrix to the fracture during de-pressurisation half-cycles. Cyclic injection below bubble point pressure, designed to ensure gas saturation not exceeding the critical level, yielded additional recovery of 5.9% of OOIP. This effect may be credited to the energy of released gas, expelling the matrix oil into the fracture.
The experimental results indicate significant potential of cyclic injection to improve micro level displacement efficiency of waterflood in carbonate reservoirs.
If cyclic water injection is applied at field scale, sweep efficiency improvement from flow pattern redistribution could make an additional contribution. This has been reported by several field cases in the US, China and Former Soviet Union (FSU).
An IOC's Experience in Implementing Digital Oilfield Technologies
Authors: Hacker James M. 
Published: June 2009

Abstract
Efficient recovery of hydrocarbons in increasingly challenging environments requires new solutions to managing upstream assets that integrate expertise, processes and technology. This paper will describe how ExxonMobil is incorporating digital technologies into its upstream projects and operations to improve reliability and uptime, improve safety and integrity of operations, enhance environmental performance, and ultimately to increase field recovery. The primary focus is on examples that illustrate the benefits of leveraging a Global Functional Organization and worldwide standard asset management processes to integrate expertise, work processes and digital technologies to maximize asset performance. The paper concludes by presenting five critical success factors in implementing digital oilfield technologies.
Rock-Typing of Upper Jurassic (Arab) Carbonates, Offshore Abu Dhabi
Authors: Lehmann Christoph T. , Hosany Khalil I. Al , Cobb David O. , Al-Hendi Ahmed 
Published: June 2009

Abstract
A preliminary rock typing scheme for the Upper Jurassic was established on Arab reservoirs on a field offshore Abu Dhabi. This study was performed in order to assist in the reservoir modeling and ultimately in the accelerated development scheme of the field. The study is based on 165 samples from all the Arab reservoir levels (Arab A, B, C, D) in 6 wells. These samples were selected to cover all the reservoir facies and the range of porosity and permeability. All these samples have MICP data, thin section and porosity/permeability data. The objective was to identify the major rock types occurring in the Arab reservoirs from these samples.
Rock types of the Arab Formation can be divided into 3 major rock type groups: Limestone, Dolomite, and Anhydrite. Limestones predominantly occur in the Arab D reservoirs, the dolomites in the Arab A, B, and C. Anhydrite occurs as non-reservoir, intraformational seal, and/or baffle between Arab, A, B, and C or is intercalated in these reservoirs.
Six rock types were identified in the limestone reservoirs (L1 to L6) and five rock types were identified in the dolomite reservoirs (D1–D5). Various degree of overlap in reservoir properties do exist between some of these sub-groups. The dolomite rock types are easier to be classified into rock types compared to the limestone because of their uni-modal pore throat size distribution and well-defined capillary pressure curves. Reservoir quality is related to crystal shape, size, crystal-to-crystal contact, and dissolution.
Limestones are much more complex and reservoir quality is controlled by mud content, grain size, sorting and diagenesis. Dissolution creating vuggy porosity can create high perm zones if the vugs are connected in both dolomites and limestones. Three limestone rock types show a pronounced dual-porosity system which is difficult to characterize with conventional rock typing methods.
This work is being used to assist in the detailed characterization of the offshore field and in the ongoing field development.
Innovative Approach to Incidents Investigation Improves Contractors HSE Performance
Authors: Ataya Zaher M. 
Published: June 2009

Abstract
The present paper focuses on an innovative approach to HSE incident management system, (reporting, investigation and close out process), which improved drilling contractors and service companies' HSE performance and assisted in the significant reduction of the total recordable incidents rate (TRIR) and lost time injury frequency (LTIF). The paper is a combination of best practices and practical experience with incidents investigation.