bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Acid Gas Removal From Natural Gas Using Amine Mixtures
Authors: Erayanmen Wilson-Air 
Published: February 2011

Abstract
Removal of Acid gases from natural gas is currently a global issue; apart from it important in meeting the customer's contract specifications and for liquefaction process specification needs, it is also a measure for reducing the global CO2 emission. Natural gas process throughput rate is mainly based on the product specification control and the natural gas market drive for acid gas free products. This paper considered the gas treatment implications of the product specification; in profile trend with process throughput. The aim of this study is to investigate the possibility of using different amine mixtures as absorbent solvent in natural gas treatment process; using HYSYS software program as the simulation tool. A base case of Acid gas removal process (Non-Amine mixture based) is simulated using HYSYS 3.2 process simulator to create a steady-state process. The simulation program is then used to sensitized Amine mixture based process; through the modification of physical, thermodynamics and transport properties of the gas/amine process and also to develop an improved amine process that is environmental friendly. Simulation studies and analysis is carried out on an existing natural gas treatment plant. The simulation result shows that the application of amine mixture increases acid gases (C02 and H2S) pick-up in amine based solution with no corrosion effect. It also shows that regulating and increasing amine mixtures flow rate; encourages CO2 capturing capacity at low temperature, lowering the amine residence time in the stripper and reduces the tendency for CO2 emission.
Semi-Infinite Channel Sands: The Signature and Effects of Wedge Angles
Authors: Idigbe Koso I. , Obeahon Percy Paul 
Published: February 2011

ABSTRACT
This paper presents the results of pressure-test numerical simulations performed on channel sands in order to capture the impact of reservoir heterogeneities on pressure transient behavior beyond what has been available to date.
Channel Sands, geological features characterized as long narrow reservoirs, were studied to model the effects of wedge angles, very important in the understanding of channel geometries.
The study shows that the effect of a semi-infinite channel having non-parallel sides can be obtained as a combination of a well test responses of a well placed between wedges. Varying the wedge angle was seen to affect the late-late time pressure response but did not affect the total system behavior. Also, varying The well location on a combined meander as well as the channel position in a combined meander, was seen to affect the middle-late times response but did not affect the total system behavior as a meander.
The ability to model these complex Channel bodies will greatly reduce the uncertainties associated with assigning the right geometries in reservoir studies. The estimation of reserves, a key factor in field development, is highly dependent on the size of the reservoir(s) in the field, a function of geometries.
Replacement of Existing ESD Valves with New SIL Rated ESD Valves: A Case Study of Production Optimization and Enhancement of Process Safety and Integrity in Kuwait Oil Company
Authors: Al-Khaledi Sadoun Mutar , Abdulaziz Naser , Bora Dwaipayan 
Published: February 2011

Abstract
Emergency Shutdown (ESD) valves play a vital role in meeting production and safety requirements in a process plant. On headers of a Gathering Center (GC), ESD valve assemblies are installed to protect the downstream processing equipment from over pressure, high level and other emergency conditions. ESD valves typically stay in open position for months or years awaiting a command signal to operate. Little attention is paid to these valves outside of scheduled turnarounds. The pressures of continuous production often stretch these intervals even longer. This leads to build up or corrosion on these valves that prevents them from moving. For safety critical applications, it must be ensured that the valves operate upon demand. The SIL-3 rated ESD valves complete with auto self-testing and acoustic leak detection are designed to operate upon demand. This paper discusses the enhancement of safety and integrity of the GCs following installation of new SIL-3 rated ESD valves in its headers.
Kuwait Oil Company is carrying out projects to enhance Safety Integrity Level (SIL) of header ESD systems by providing new SIL-3 certified ESD valves as replacement of the existing valves in its GCs.
This paper examines the numbers arrived in calculating various performance indicators of ESD valve reliability and interpret these for benefit of the engineers. It is evident that there is a marked improvement in the failure rate and hence integrity of new ESD valves compared to old system. This has also remarkably optimized production, leading to substantial savings.
If ESD valves are called into use, they have to work reliably, because the consequences of failure will be far more serious than the disruption, when they work. The new SIL-3 rated ESD valves are designed to operate when called for, thus enhancing safety and integrity of the GC.
Successful Improving Produced Water Treatment in Pul-A Field, Peninsular Malaysia Operations, PETRONAS Development and Production
Authors: Rosli Rosliza Hanim , Josli Hamidi , Osman Azmee , Hadi Sriyanta 
Published: February 2011

Abstract
Pul-A field is an oil producing field located about 260 km offshore Terengganu, eastern Peninsular Malaysia in a water depth of about 77 meter in the South China Sea (Refer to Figure 1). The field is equipped with oil and gas processing plant, gas injection facilities and gas compression system. Pul-A was brought to production in March 1978 with an average oil production of 1,400 barrels oil per day (BOPD). The oil production peaked at around 35,000 BOPD in 1979. Previously produced water was treated using a corrugated plate interceptor (CPI) unit prior to discharge. The water treatment is required to ensure the effluent water quality is in compliance with regulatory effluent discharged water requirement of maximum oil content of 40 parts per million (ppm). The CPI unit was down several times in 2005 and 2006 causing twenty daysproduction deferment with an estimated opportunity loss of USD 6.8 Million. In line with the effort to maintain the oil production by flowing high water cut wells, a new produced water treatment technology was chosen to replace the existing CPI unit. The new equipment is a vertical separator that is equipped with acombination of induced gas and cyclonic fluid motion to improve solids, water and oil separation. Pul-A team successfully installed the new equipment with challenging modifications and tie-in work in aging facilities. The unit that was commissioned in October 2010is capable of treating produced water up to 15,000 barrel water per day (BWPD).
Tight Gas Sands Development is Critical to Future World Energy Resources
Authors: Khlaifat Abdelaziz , Qutob Hani , Barakat Naiem 
Published: February 2011

Abstract
With the increased global demands on oil and gas, operators strive to maximize production by conducting more advanced drilling operations, such as extended reach, horizontal and high-pressure/high-temperature (HP-HT) drilling and are expanding globally into drilling unconventional resources. Unconventional gas resources offer significant gas production growth potential in the coming years, currently accounting for 43% of the US gas production. Tight Gas Sands (TGS) represents approximately 70% of the unconventional production and significant reserves are yet to be developed. Although "tight gas sands" are an important type of basin-centered gas reservoir characterized by low permeability, abnormal pressure, gas saturated reservoirs and no down dip water leg., not all of the TGS are Basin-centered gas (BCGAs). An intensive technology effort to both better understand tight gas resource characteristics and develop solid engineering approaches is necessary for significant production increases from this low-permeability, widely dispersed resource. Gas production from a tight-gas well will be low on a per-well basis compared with gas production from conventional reservoirs. A lot of wells have to be drilled to get most of the oil or gas out of the ground in unconventional reservoirs
However, economical production of TGS is very challenging as it exists in reservoirs with micro-Darcy range permeability and low porosity but has a huge potential for production in the future. Poor permeability results in lower gas production rates from TGS reservoirs. In order to economically develop TGS resources an advanced technology has to be developed and implemented. Most of the TGS reservoirs are characterized by being thick (hundreds to thousands of feet thick) and multilayered where their gas production rates can be enhanced by hydraulic fracturing. Although service companies have large capabilities for conventional/unconventional reservoirs but the used technology to drill, complete and stimulate tight gas reservoir is quite complex and the results are often unexpected and unforeseen. The appropriate completion methods and stimulation techniques in these reservoirs are dependent on many parameters and variables, such as depth, pressure, temperature, capillary and overburden pressures and the number of sand layers.
This paper provides a technical overview of the state of the art technology used to develop those reservoirs. This work takes a multidisciplinary approach to better understand how gas can be produced from tight gas sand reservoirs. Two real case histories will be presented and discussed; Travis Peak formation in eastern Texas, USA; and Risha gas field in eastern Jordan.
Numerical Well Testing Using Unstructured PEBI Grids
Authors: Deng Hui , Bao Xia , Chen Zhangxing , Wang Ruihe 
Published: February 2011

AbstractHistory matching is challenging for low permeability gas reservoirs because of significant differences between the static properties in a geostatistical model and in-situ properties measured from well testing. The literature has documented that reduction of in-situ permeability due to overburden pressure can be in two orders of magnitude. Numerical well testing provides a way of tuning a static model with dynamic well testing information. However, a traditional single well testing model using Cartesian LGR (local grid refinement) is not ideal for predicting the pressure transient behavior. Furthermore, a stand-along well testing conditioned model cannot be fully coupled into a full-field model to honor the flow regime.This paper presents a methodology of using a PEBI (perpendicular bisector) grid in a simulation model to match well test data for a low permeability gas reservoir in Canadian Foothills. A PEBI-LGR grid is created around the well and a vertical hydraulic fracture is implemented to match the post fracture pressure build up. History matched parameters include static properties and hydraulic fracture properties such as fracture half length and fracture permeability. Finally, well testing conditioned effective properties will be stochastically populated into the simulation model for the full field history matching. In conclusion, the PEBI gridding technique links well testing with reservoir simulation and provides the most efficient workflow in modeling unconventional gas reservoirs with multi-stage hydraulic fractures.
Extending Well Productive Life by Acid Re-fracturing in a High Pressure/High Temperature Tight Gas/Condensate Carbonate Reservoir in the Jurassic Formation of North Kuwait
Authors: Kabir Mir , Dashti Qasem , Singh J. R. , Pradhan San Prasad , Nugraha Ikhsan , Hai Liu , Al-Ghadhban Hamed 
Published: February 2011

Abstract
One of the most common strategies to effectively produce from tight gas carbonate reservoir is by completing the wells with acid fracturing technique, where the etched fracture half length alters the flow pattern from formation in to the wellbore with its high conductive flow path.
The treatment success, apart from operational aspects, is also measured by addressing the issue of fractured geometry created, zonal coverage achieved and the actual well potential based on its petro-physical and rock mechanical properties and relate this to well’s production behavior. In the high pressure/high temperature tight rock formation with minimum number of natural fractures, it is very common to observe immediate production gain following an acid fracturing treatment.
The well in discussion was acid fractured 3 years earlier with almost 90% of cumulative production occurred during the last one year. It was observed that it is declining faster than expected. Review of the well performance led to two main possible causes, i.e. reservoir pressure decline and reduction in fracture length/conductivity. Acid re-fracturing strategy was considered and decided to restore the well’s productivity by further extending the fracture half length by enhancing the fracture conductivity.
The results showed that Productivity index (PI) increased by 2.5 folds during the post treatment production test. However, after 3 months of continuous production, the PI declined down to 1.2 folds despite the pressure build up performed indicated fracture conductive behavior. This paper discussed key lessons learned to further improve the outcome by integrating production analysis, reservoir quality evaluation as well as stabilized production expectation with stimulation approach during candidate evaluation process.
A Better Understanding of Finite Element Simulation for Shale Gas Reservoirs through a Series of Different Case Histories
Authors: Jayakumar R.. , Sahai V.. , Boulis A.. 
Published: February 2011

Abstract
Production from the extremely low permeability reservoirs found in shale gas plays results in very large pressure gradients at and around the sand face. Finite-element modeling technology, in which a large number of closely-spaced nodes are placed near hydraulic fractures, is the best approach for replicating the reservoir and completion complexity required to model horizontal shale gas wells. The primary objective of this work is to demonstrate how the performance of three Haynesville Shale gas wells were modeled using this technology. Each of these three wells exhibits the large early production decline typically observed in the Haynesville. Case histories for these wells show how the finite-element software can be used to simulate the mechanisms thought to contribute to the observed production decline. The workflow used to model performance demonstrates how petrophysical, stimulation, and flow modeling are utilized to understand the key reservoir and completion mechanisms that affect production behavior of shale gas wells.
Effects of Block to Block Interaction on Oil Recovery from South Pars Oil Layer
Authors: Sani Reza Rezaei , Afsari Meisam , Amani Mahmood 
Published: February 2011

Abstract
This article investigates the effects of block to block interaction, gravity drainage and capillary continuity, on oil recovery from South Pars oil layer during primary production and gas flooding. For choosing the best oil production and EOR scenarios, the necessity of investigations like this study is obvious. In addition this work can be extended to other Iranian fractured reservoirs.
Sensitivity analyses during primary production and immiscible gas injection are performed by using CMG/IMEX simulator1 based on a very simple single porosity model but very close to dual porosity/permeability modules of this simulator.
The objectives of this article are: Investigation of main matrix-fracture fluid exchange mechanisms (like gravity drainage and capillary imbibition) during primary production from South Pars oil ring and gas injection into South Pars oil ring. Emphasizing the importance of issues such as capillary continuity between matrix blocks, reinfiltration of fluid from higher to lower blocks and block shape on flow processes and oil recovery during primary production and immiscible gas injection in South Pars oil layer. By characterizing the fractured/non-fractured reservoirs and finding the main oil recovery mechanisms, reservoir management can be done scientifically at the best time and at the best location.
Drilling Optimization in Unconventional and Tight Gas Fields: An Innovative Approach
Authors: Holdaway Keith R. 
Published: February 2011

Abstract
The majority of the technically recoverable natural gas is present in unconventional reservoirs such as tight sands, shale, and coal beds. On account of the implicit high costs associated with these unconventional and deep gas assets, it is of paramount importance to garner as much knowledge from potentially disparate and limited data sources. The objectives must be minimization of drilling and completion times, constraint of risks, quantification of uncertainty and ultimately maximization of the lifetime of a well’s productivity.
This paper illustrates an advanced analytical methodology that aggregates and integrates data from a multitude of sources, performs a robust quality control, correlates and discovers patterns to enable engineers to determine more efficient and accurate exploitation strategies. It proposes an approach based on an advanced analytical framework that introduces an exploratory data analysis step for reservoir characterization, followed by determination of key production indicators and multivariate methodologies to classify wells. With improved understanding of inherent correlation between geology, reservoir, rock mechanics, frackpack process and proppant fluid and well performance, it is feasible to cluster the wells in accordance to the overriding production indicators, thus dividing the field into clearly defined segments. The statistical output enables mapping via a transparent classification of best possible wells to known geology and reservoir conditions to identify and locate poorly-drained zones and effectively neccessitate less drilling to achieve production targets.
Hydraulic Fracturing of Naturally Fractured Tight Gas Formations
Authors: Leguizamon Javier , Aguilera Roberto 
Published: February 2011

Abstract
A workflow is presented for modeling actual hydraulic fracturing jobs in tight gas formations of the Western Canada Sedimentary Basin (WCSB). Matching of hydraulic fracture length and resulting gas production from past jobs provides a learning curve that allows design optimization of future fracturing jobs.
Key parameters needed for modeling the design of hydraulic fracturing jobs in these types of formations are discussed and include properties such as porosity (matrix, natural fracture and isolated or non-connected), permeability (matrix and natural fracture), water saturation (matrix and natural fracture), shear velocities (even when direct measurements are not available), Poissons ratio, shear modulus, Young modulus, Biot constant, overburden, pore pressure, and net stress. The critical evaluation of these properties provides a valid representation of the tight gas formation and what the natural gas production outcome from the hydraulic fracturing job might be. Important recommendations to achieve a correct integration of logs, well testing, production decline analysis, and 3D modeling of the hydraulic fracturing job are also presented; as wells as an understanding of the differences that can arise from each source of information. The paper incorporates petrophysical and new linear-dominated well testing and production decline analysis methods using triple porosity models for matching petrographic work and production decline; and for quantifying rock properties such as natural fractures and slot porosity, intergranular porosity and isolated non-effective porosity.
It is concluded that even though each tight gas reservoir is unique and as such, should be considered as a research project by itself, the workflow presented in this study could prove to be of value in other regions of the world where tight gas formations are present.
Well Completion Strategy and Optimization in a North Dakota Bakken Oilfield
Authors: Zander Dennis , Seale Rocky , Snyder Daniel J 
Published: February 2011

Abstract
First discovered in 1951, development of the Bakken formation in the Williston Basin has been problematic and inconsistent. However, technological advancements in horizontal drilling and completions in the past decade have steadily improved production results and consistency on a well by well basis. So much so, that the United States Geologic Survey (USGS) reported in 2008 that the undiscovered, technically recoverable oil in the Bakken was between 3 to 4.3 billion barrels.
How many fracture stages to run and how far apart to space stages in horizontal wells are prevalent questions asked by the oil and gas industry. This study provides insight into the advantages of various stage numbers and optimum stage spacing by analyzing up to 21 months of production results from horizontal wells targeting the Bakken in the Stanley Field, North Dakota. These wells were completed with open hole, mechanical systems (OHMS) and production is compared to offset wells and field averages.
Advancements in OHMS completion and fracturing technology have enabled maximized production from this asset. The lessons learned and methodology can be utilized for other unconventional oil and gas plays around the world.
A Comprehensive Approach to Surveillance in Appraisal of a Tight Gas Project in Central Oman
Authors: Clark Robert A , Al Busafi Badar , Adil Imtiaz , Al Lawati Hussain , Huggins Paul , Rainey Steve 
Published: February 2011

AbstractBP’s Khazzan-Makarem (KM) appraisal project is located in Central Oman. BP committed to appraise four deep tight gas reservoirs and has drilled seven wells to date. An Extended Well Test (EWT) facility is designed to provide a long term (multi-month) flow test of those wells.Basic information relating to trap, seal, areal extent, and Gas-in-Place (GIP) is not the most significant problem in this appraisal project; the most important issue is long term well performance. The tight gas nature of these reservoirs results in considerable uncertainty in prediction of future deliverability. It is not uncommon for tight gas wells to achieve excellent flow rates after fracture stimulation, yet decline precipitously over a short period of time (typically months) once on production. Prediction of well performance based on this early flow rate is a highly unreliable indicator of long term performance. This can result in drastic miscalculations for Full Field Development (FFD) planning and economics.Extensive surveillance activities are critical to evaluate this uncertain behavior. An examination of stimulation, well testing and Pressure-Build-Up (PBU) analysis in these wells provides the starting point for understanding well deliverability.BP’s KM appraisal wells were planned to selectively target reservoirs addressing variations in reservoir quality and continuity. Completions were designed from the start, to facilitate extensive stimulation programs. Surveillance programs were constructed with permanent down hole gauges (PDHG) to provide critical real time information about the stimulation efforts, well testing, fluid composition analysis, and extreme long term (~ 1 year) PBU. All of this effort provides guidance in planning the EWT facility for an extended flow testing campaign which will feed into FFD planning. Achieving commercial rates in tight gas reservoirs in Oman has proved to be challenging. However this comprehensive appraisal and surveillance program is providing a growing level of confidence in the development potential of the Khazzan-Makarem project.