bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Experiences Using Foam to Cleanout Sour Gas Wells in Saudi Arabia
Authors: Al-Hakami Ibrahim , Franco Carlos , Leal Jairo Alonso , Garzon Francisco , Noguera Jose , Izquierdo Guillermo 
Published: December 2007

Abstract
The use of coiled tubing to perform fill clean outs or to remove scale build-up or any other type of restriction inside the wells is becoming one of the most common field applications in Saudi Arabia. In fact, based on the increasing scale tendency in the gas wells, Coiled Tubing scale cleanout represent one of the biggest challenges for Coiled Tubing service activities, especially in gas wells. The trend towards more complex well trajectories, lower bottom hole pressures because of reservoir pressure decline, heavier and harder scale materials and high H2S contents, impose operational constraints on this essential service; making the selection of the cleanout fluid an important component of the design criteria.
Inefficient wellbore cleaning is the main source of costly problems such as stuck CT pipe. A well-known solution to solve the problem is to increase the velocity of the cleanout fluid in the annulus, which will decrease debris concentration in the annular space. The increment of the annular fluid velocity is limited because of the CT friction and surface equipment. Under this scenario, the fluid with proper viscosity to transport the solids is required, even in low annulus velocity scenarios.
Foam was selected as the cleanout fluid for this particular type of wells because of its ability to keep the debris in suspension and transport it out of the well and to control the reservoir pressure to perform the cleanout operation in near balance or slightly overbalanced conditions.
This paper describes some field experiences using foam as a fluid to transport the removed material out of gas wells, independently of well deviation, using coiled tubing. It describes the technical details behind this approach as well as the operational results and best practices for field applications.
Technological Applications Redefining Mature Field Economic Limits
Authors: Abduldayem Mohammed A , Al Douhan Nader D. , Baluch Zulfiqar A. 
Published: December 2007

Abstract
Nowadays, high water-oil ratio producing fields are responsible for a significant portion of world oil production, particularly from mature fields where production practices are the key to managing operating costs and optimizing profit. In today's environment with relatively high oil prices, technology application in field management plays a critical role in improving production performance and recovery, as well as redefining the economic limit of the field.
Excessive water production is one of the main threats to the longevity of oil wells. It results in increased production cost and higher field capital investment requirements in surface facilities to produce and handle water. Saudi Aramco has taken major steps in applying technologies on both newly developed and mature fields. These technologies had contributed to a remarkable water production reduction in the Abqaiq Field. Technologies such as; smart completion, side tacking at the top of the reservoir, maximum reservoir contact (MRC) wells, Equalizer and interval control valve (ICV) production technologies, intermittent production strategy and rigorous water shut-offs for high water-oil-ratio (WOR) wells, has resulted in reversing the Abqaiq field's water cut trend from 42% in 2004 to 32% by the end of 2006.
Optimization of Gas Well Productivity by Controlling Water Production
Authors: Shar Amjad Hussain 
Published: December 2007

Abstract
It is seen that gas wells if produced without planned rates may produce waterpre-maturely. Production of water basically loads the subject well bygenerating hydrostatic head within the well tubing. Secondly the waterproduction alters the in-situ gas saturation in near well bore region resultingchange in the relative permeability. Both these reasons make the subject wellproblematic due to decrease in well productivity and increase in the welloperating cost. Also the handling of produced water is uneconomical in manycases.
The work done for this study is general in nature, though the essence ofthis work comes from data collected from different gas wells having waterproduction problem. This study gives an overview of all the methods andtechniques, which can be used for, expel-out such problems and optimize gasproduction. Main stress has been given on Tubing Performance Curve study inorder to select best tubing size and calculation of the optimum rates againstselected tubing size. General tubing performance curve are also presentedshowing the behavior of the well before and after water production.
On the basis of study of different techniques related to the Gas wellproduction optimization and water production control we became, able to give asolution of interchanging the well tubing strings without purchasing any newstring pertaining to large gas fields where different tubing sizes are used indifferent wells.

Introduction
It is considered that wells producing dry gas have usually lower flowingbottom-hole pressure [1]. Liquid loading happens when the gas does not haveenough energy to carry the water out of the wellbore. Water accumulates at thebottom of the well, generating backpressure in the wellbore and blocking gasinflow [2]. For the optimization of the production of the gas it is necessaryto unload that water from the wellbore so that there should occur a decrease inthe backpressure of the static water column.
Case History: Seismic Facies Analysis Based on 3D Multiattribute Volume Classification in Shadegan Oilfield – Asmari Reservoir, Iran
Authors: Arianfar Abdonabi , Khedri Behruz , Haghighi Maziar , Golalzadeh Alireza , Poladzadeh Mahmod , Mehdipour Zargham 
Published: December 2007

Abstract
Shadegan oilfield is located in Khuzestan province in southwest of Dezful embayment, southwest of Iran. The latest 3D surface seismic was carried out in 1999 over an area of 192 km2 in this field to resolve structural ambiguities, delineate exact dimensions of the field, estimate reservoir parameters and perform a seismic facies analysis over the field for producer zones of Asmari reservoir.
Asmari reservoir in this filed consists of three producer zones including zones 2, 5 and 6. This paper will discuss about facies analysis of these zones based on 3D seismic multiattribute volume classification.
A sophisticated approach was undertaken to perform multiattribute seismic facies analysis in the Asmari reservoir for each zone. Many lithology sensitive attributes were extracted from the post-stacked 3D seismic data and some of them were rejected using a multidimensional correlation technique in order not to take part in classification algorithm and determining the optimum set of attributes to use in the classification. This helped with data redundancy problems inherent in multiattribute analysis and avoiding independent attributes by choosing an appropriate set of attributes for the classification. So, the seismic attributes used for the facies classification included Signal Envelope, Heterogeneity Seismic Amplitude, Integration Seismic Amplitude, Magnitude Seismic Amplitude and Volume Reflection Spectrum. The objective was to integrate the seismic attribute information through the use of an unsupervised clustering technique. Clustering techniques are widely recommended tools for classification issues.
The k-means algorithm is widely accepted as the standard technique of detecting different classes automatically from the measured data. This algorithm provided a facies database that was used to estimate lithofacies over the whole field. Using the clustering technique, three major lithologies including sandstone, carbonate and shale have been classified and displayed for each producer zone. Classified facies were calibrated to drilled wells and the results were confirmed.
Performance Analysis of Horizontal Wells for Underground Gas Storage in Depleted Gas Fields
Authors: Bagci A. Suat , Ozturk Bulent 
Published: December 2007

Abstract
Underground gas storage is a common activitity in countries with major transport and distribution gas pipeline infrastructures, which allows to efficiently resolving demand seasonality problems. The first ever underground gas storage project in Turkey is being carried out in the KM field with injection and withdrawal operations. Optimization of gas storage field was enabled by an improved reservoir and geologic description, including the evaluation of deliverability and storage capacity in the reservoir. Based on available information and those generated by simulation model, KM field is the best candidate for underground gas storage.
The KM offshore natural gas field was discovere in 1988 located about 3 km off the shore of Silivri in the Marmara sea. The field was initially planned to be developed with 3 wells, but recently 2 additional wells were added during the development of the field hence increasing the depletion rate. In this study, after gathering necessary reservoir, fluid, production and pressure data, IMEX (CMG) simulation program was used for history matching of depletion of the field. Reservoir performance after history matching using depletion scenario was predicted and depletion last for 4 years.
In 2005, 5 ERD wells were drilled in KM field from onshore drilling site location for gas storage application. Five scenarios were developed for forecasting of injection and withdrawal performance of the reservoir. These scenarios were used 5 newly drilled horizontal wells with combination of existing vertical wells. With a predetermined injection rate of 65 MMscf/day was set for all the wells and among all scenarios, 5 horizontal – 5 vertical injectors and producers was the most successful in hamdling the gas inventory and he injection period was 5 months and production period was 7 months, respectively. After the determination of the well configuration, the optimum injection rate for the entire field was obtained as 65 MMscf/day by using horizontal gas injection wells. The total produced gas volume until 2012 was estimated as 394 Bscf with this optimum gas injection where the maximum average reservoir pressure was 1901 psi and cushion gas pressure was 1270 psi by withdrawal.
Integrated Reservoir Characterization and Modeling of One Iranian Naturally Fractured Reservoir Using Laboratory and Field Data
Authors: Abdi Yaser , Ghane Mehdi , Haghighi Ahmad Reza 
Published: December 2007

Abstract
This Field is a Cretaceous fractured oil bearing reservoir in the south of Iran composed of tightly packed limestone characterized by high porosity but poor permeability and it is seems to be oil wet. The oil is relatively heavy with API of about 21.3 degrees, viscosity of about 6.85 centipoises and solution GOR of 250-280 scf/stb.
The reservoir energy is limited to fluid expansion and water in flux. The strength of which will be weak because of the low permeability of the rock, as a result the reservoirs are considered to have very poor flow potential. Our studies focused on characterization, modeling and simulation of different production scenarios.
A model was constructed using a three-phase, three-dimensional, dual porosity simulator (ECLIPSE). Because of Existence of uncertainties in SCAL data understanding of two key issues are addressed, Reservoir rock typing and rock wettability. This study emphasized detailed analysis of relevant parameter to these issues which estimated using combination of core, log data and wireline formation tester measurements by developing a numerical model. Several studies were conducted after successfully matching performance of built model with production history of DST results. Eventually the model was applied to run a series of sensitivity simulations for optimization of injector locations, Water injection and gas injection (miscible and immiscible) to increase reservoir oil recovery.
Based on simulation results for different scenarios water injection outperform the others. Miscibility experiments performed in PVTi showed that the minimum miscibility pressure (MMP) is around 12000 psia.
Immiscible gas injection process suffers from unfavorable mobility ratio and high producing GORs, which makes sweep efficiency to decrease and eliminates possibility of ESP usage occurs. This study provides Guidelines for any future development plan in this field.
Analysis of Stress Sensitivity and its Influence on Oil Production from Tight Reservoirs
Authors: Lei Qun , Xiong Wei , Yuan Jiangru , Cui Yuquan , Wu Yu-Shu 
Published: December 2007

Abstract
This paper presents a study of the relationship between permeability and effective stress in tight petroleum reservoir formations. Specifically, a quantitative method is developed to describe the correlation between permeability and effective stress, a method based on the original in situ reservoir effective stress rather than on decreased effective stress during development. The experimental results show that the relationship between intrinsic permeability and effective stress in reservoirs in general follows a quadratic polynomial functional form, found to best capture how effective stress influences formation permeability. In addition, this experimental study reveals that changes in formation permeability, caused by both elastic and plastic deformation, are permanent and irreversible. Related pore-deformation tests using electronic microscope scanning and constant-rate mercury injection techniques show that while stress variation generally has small impact on rock porosity, the size and shape of pore throats have a significant impact on permeability-stress sensitivity. Based on the test results and theoretical analyses, we believe that there exists a cone of pressure depression in the area near production within such stress-sensitive tight reservoirs, leading to a low-permeability zone, and that well production will decrease under the influence of stress sensitivity.
Evaluation of the Results of Gas Storage in a Gas/Condensate Reservoir in the Appalachian Basin
Authors: Aminian K. , Brannon Alan , Ameri S. , Bhavsar A. 
Published: December 2007

Abstract
A gas condensate reservoir in the Appalachian Basin has been converted into a gas storage reservoir. Te results of the first storage cycle are presented. When gas is injected into a depleted gas condensate reservoir, the remaining condensate will evaporate and enrich the injected gas. The degree of mixing among the residue gas, residue liquid, and the injected gas will determine the composition of the gas in the reservoir and the liquid yield at the surface when the gas is withdrawn. The results of the first storage cycle clearly indicated that complete mixing was not achieved in the reservoir. The storage gas compositional changes, due to partial mixing with the native fluids, have both positive and negative impact on the operation of storage field. The lower liquid yields reduce the requirements for liquid handling. However, the heavier hydrocarbons remain in the reservoir longer and the liquid production is extended to a greater number of storage cycles. The liquid yields were low initially because the withdrawn gas had been in the reservoir for a short period of time. Furthermore, this gas did not come into contact with significant liquid due to liquid evaporation. The liquid yields subsequently increased up to a maximum before they declined again. The decline in liquid yields was caused by retrograde condensation in the reservoir. The storage gas compositional changes reduced the storage capacity by 12 percent. The reduction in gas capacity was economically advantageous since it reduced the base gas requirements. Finally, the results of first storage cycles were utilized to optimize the liquid recovery at the surface facilities for the subsequent cycles to prevent liquid drop out by retrograde condensation in the pipeline.
Estimation of Skin Factor By Using Pressure Transient Testing Results of a Single-Rate Well Test
Authors: Gunaydin D. , Mohaghegh S. D. , Gaskari R. , Aminian K. 
Published: December 2007

Abstract
About one-fifth of the natural gas used by Americans each winter comes from natural gas storage sites. Gas storage is the primary means for the gas industry to manage fluctuations in supply and demand. Natural gas can be stored in a variety of ways. Most commonly, it is held in underground formations, in depleted oil or gas reservoirs, or in natural aquifers.
Many gas storage wells show a decline in deliverability as a function of time due to several damage mechanisms. The remedial operations such as stimulation and workovers are used to restore the loss in deliverability and to enhance the productivity of a well.
Candidate selection for the stimulation or workover process is generally based on well history. Skin factor is an important parameter to predict the well performance. Skin is usually calculated from a multi rate well test (MRT). However performing a MRT on a regular basis is an unattractive activity when considering the economic issues. First of all, performing a well test may cause temporary production or injection interruptions. Secondly, the cost associated with well test is considered as an operating expense, a fact that does not help the overall economics of operating a Gas Storage Field. Single Rate tests (SRT) are also performed to estimate the deliverability, but they do not contain sufficient data in order to estimate true skin factor.
The objective of this study is to introduce a new methodology to enhance the current practices of estimating true skin factor from a SRT. This method includes history matching of the actual MRT and then estimation of skin value from SRT using the history matched model. Using this methodology it is shown that change in the skin can be estimated with reasonable accuracy.
The Oriskany Sandstone of Guernsey County, Ohio: A Study of High Surface Treating Pressure Response During Hydraulic Fracturing
Authors: Myers Roger , Martin Jason , Criser Brent 
Published: December 2007

Abstract
According to a publication by J.M. Hall, the "discovery well in 1922 at Cambridge was at a depth of 3,470 feet, which was 1245 feet below the top of the "Big Lime," and gas was encountered with an open flow of 8,000 M, and a rock pressure of 1,150 pounds. By 1925 eleven wells had been completed in this area and the field had started to go to water." Since the 1950s Columbia Gas Transmission Corporation converted 48 of the wells to gas storage1. The EIA lists Guernsey Storage as having a capacity of 7.3 BCF and a maximum daily deliverability of 36.6 MMSCF2.
Around the Appalachian Basin the Oriskany sandstone is known as one of the toughest sands to drill and fracture stimulate. Perhaps, the most extreme example lies under the NW corner of Guernsey County, Ohio (Figure 1). One interesting geological point of interest here is that the Cambridge cross-strike structural discontinuity is located on the western edge of the gas storage field in Guernsey County. The Appalachian Gas Atlas states that there is "no reflection or influence of this basement activity on the Devonian Oriskany."
Figure 1 Arrow points to approximate location of Columbia Gas Transmission Corp's Guernsey Oriskany storage field.
Columbia Gas Transmission Corp, as part of its well reconditioning program, routinely works over some of the wells in this field. Hydraulic fracturing is part of the work-over process to restore lost deliverability. This paper will explore the high surface pressure responses seen during both original frac jobs and refracturing treatments. The fracturing gradients are routinely in excess of the overburden gradient. Interestingly, these same pressures are not experienced in the Silurian age Clinton sandstone that lies below the Oriskany across the field. The treating pressures prompted further investigation to determine their origin and to help improve future stimulation treatment designs. Three- (3) additional wells were to be stimulated this spring in the Guernsey field and their pressure response will be included in this paper.
Pseudo-3D Seismic Use for Development of First US Offshore Gas Storage Facility
Authors: Toelle Brian E. , Kaufman Peter , Chowdhury Nitin , Brown Kenneth G. , Knolle Edmund 
Published: December 2007

Abstract
The North Dauphin Island Gas Field, located in Alabama State waters, was discovered in 1990 by Arco and has produced 64 BCF of gas during its primary production phase. This field was productive from the Dauphin Sand, a Late Miocene sandstone located at an approximate depth of 1,850 feet TVDSS. The field's reservoir has both high porosity and permeability and it has been produced from five boreholes, two near-vertical and three horizontals. One of the near-vertical wells was sidetracked after the original borehole encountered unexpectedly poor reservoir.
In preparation for converting the North Dauphin Island Field and two adjacent smaller Dauphin Sand fields to the first offshore gas storage facility in the US, all available geologic and geophysical data were re-examined. This storage conversion project will result in up to 21 new deviated injection and withdrawal wells being drilled, in addition to several sub-vertical monitoring wells. The targeted reservoir performance for this facility is 50 Bcf high deliverability with injection and withdrawal rates of 1 Bcfd+. Because of the substantial investment required, a complete understanding of the reservoir is vital. The objective of this study was to utilize all available geological and geophysical data to perform a complete reservoir characterization and simulation to determine the optimum design and placement of horizontal injection/withdrawal boreholes and monitoring wells.
During its primary production phase, a set of parallel 2D seismic lines was acquired over much of the field. This data includes 40 towed dual streamer lines, with approximately 300 ft line spacing. Shallow mud gas detrimentally affected some of the seismic signature making normal reservoir characterization of the Dauphin Sand difficult.
As part of this study the original parallel 2D seismic data were re-interpreted using 3D tools and methods. This was accomplished by first loading 40 individual 2D seismic lines as one 3D survey into a geophysical workstation. A shift in the
CDP numbering on some of the lines was necessary to load them as a 3D survey and still maintain a correct special relationship. 3D tools, such as seismic variance and voxel picking, were applied during the interpretation of this pseudo 3D survey. Additionally, the flattening of progressively deeper stratigraphic units proved to be instrumental in obtaining a clearer image of the reservoir. This enhanced interpretation was then used for a more accurate static model and reservoir simulation.