bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Technique for Calculation of Well Deliverability in Gas Condensate Reservoir
Authors: Gerami S.. , Sadeghi A.. , Masihi M.. 
Published: January 2010

Abstract
Well deliverability is an important issue in forecasting the performance of many gas condensate reservoirs. Condensate accumulation near the wellbore can cause a significant reduction in productivity, even in reservoirs where the fluid is very lean. Generally, the well deliverability is affected by two pressure-drop sources due to depletion and condensate buildup.
Recently Rapid spreadsheet tools have developed to evaluate the well performance using material balance equation for depletion and two-phase pseudo pressure integral for well inflow performance. Most of them account for the effects of negative inertia and positive coupling in the calculation of gas relative permeability.
This paper introduces a new method for calculation of the well productivity in gas condensate reservoirs. This method uses the concept of two-phase pseudo pressure integral without any need to estimate the radius of two-phase region. The average reservoir pressure is calculated by using a general material balance equation. The only data required for implementing this method is PVT data, relative permeability curves and table of well flowing pressure versus time.
The approach is validated by using a single-well fine grid compositional simulation of a hypothetical reservoir model over a typical range of gas condensate reservoir parameters. The results show a reasonable agreement between the fine grid and the proposed approach. The new technique can be encoded on a spreadsheet in order to forecast the gas condensate well performance very rapidly.
Tight Ultra-deep Gas Field Production Optimisation – Development Optimisation and CO2 Enhanced Gas Recovery Potential of the Schoenkirchen Uebertief Gas Field, Austria
Authors: Secklehner Severin , Arzmüller Gerhard , Clemens Torsten 
Published: January 2010

Abstract
The Schoenkirchen Uebertief gas field is situated in the Vienna Basin, a pull-apart basin east of Vienna in Austria. The field is located inside the Mesozoic Northern Calcareous Alps thrust belt which is buried at this location by 3000m Neogene basin fill sediments. The gas was trapped in a steeply inclined thrust unit which is enveloped by Early Tertiary intraorgenic sediments. The top of the structure was encountered at a depth of 5050 m and the original gas/water contact at 5780 m. The field was and still is invisible on seismic - hence the discovery was purely based on a geologic model that was derived from outcrop studies along the western basin margin.
The field consists of intensively fractured dolomite with 3.7 % porosity and low permeability of around 3 mD. The initial reservoir pressure was 598 bar and the field contained gas with a CO2 content of about 12 %. Gas Initially In Place (GIIP) was 20 Bm3. Production from the field commenced in 1969. Until 2008, 12.2 Bm3 of gas have been produced. By optimising the production system, the expected ultimate recovery factor is 88 %.
The field has been produced by three wells located at one end of the15 km long and only 2.2 km wide structure. The proximity of the field to CO2 sources (refinery) and the well design which accounted for the high CO2 content in the produced gas makes the field a good candidate for CO2 geological storage.
CO2 injection into the field far away from the producers to optimise sweep efficiency was studied by performing compositional simulation runs. The results indicate that about 1 % incremental gas of the GIIP could be recovered in addition to avoiding CO2 emissions of 37 million tons of CO2.
New High-Density Fracturing Fluid to Stimulate a High-Pressure, High-Temperature Tight-Gas Sandstone Producer Formation in Saudi Arabia
Authors: Sierra Leopoldo 
Published: January 2010

Abstract
Local and international companies are focused on an aggressive gas exploration campaign in tight high-pressure and high-temperature (HPHT) sandstone formations. In all of the current cases, the prospective HPHT tight-gas producing layers were discovered at depths below 20,000 ft where normally the stress and temperature are extremely high in addition to the very low reservoir permeability conditions. For HPHT tight-gas formations, fracture stimulation is a required step to define the reservoir fluid and evaluate productivity.
The extreme stress and temperature conditions are the main challenges of performing fracture stimulations in HPHT environments. In high-temperature conditions, fracturing fluids especially need to be stable, induce minimum damage, and have good proppant transport capabilities.
In HPHT tight-gas formations fracture stimulation (375°F and 1.1 psi/ft at 20,000 ft), where the temperature and stress conditions exceed existing fracturing fluids application limits, there are also limits from working pressure capability of the available pumping equipment. For this need, a new high-density fracturing fluid (HDFF) was introduced to the industry. Extensive laboratory evaluation was performed to design a new HDFF and to identify a regional supplier for the high-density brine (12.3 lb/gal) used as the base fluid to mix the new crosslinked fluid. The new fluid system was successfully mixed and pumped in the field, enabling the fracture stimulation treatment of a HPHT well at lower surface treating pressure, lower horsepower, safer working environment, and using conventional 15,000-psi rated fracturing equipment. Without having this new fracturing fluid the fracture stimulation treatment would require 20,000-psi rated equipment, which is not normally available in the area.
This paper summarizes the extensive fluid qualification testing, well conditions, and lessons learned from the first field applications of the new high density fracturing fluid system in Saudi Arabia.
Fluid Contact Determination in Tight Gas Reservoirs; Formation “B” Case Study, Sultanate of Oman
Authors: Abd_Elmoula Ibrahim , Hasani Said , Jahwari Sultan 
Published: January 2010

Abstract
The traditional methods for fluid contacts determination in deep seated tight gas reservoirs are very difficult. This is a result of the down hole environment toughness and the complex nature of the rock. In addition to that, most of the tight gas reservoirs have either no, or poorly defined water table.
This paper presents a systematic methodology to determine the proper fluid contacts and to define the movable and unmovable fluids in tight gas reservoirs. It is a comprehensive workflow which integrates core measured Mercury Injection capillary pressure (MICP) and log data measurements.
MICP measurements have been used to detect the irreducible water saturation (Swirr), which was then integrated with core porosity to create the Porosity-Swirr relationships. These relationships have been transformed into bound water volume log profile (Bvwirr) using the log porosity measurements. The gas water contact (GWC) has been located by following the irreducible water saturation (Swirr) and the calculated water saturation (Sw) log profile, and the separation between the bound water (Bvwirr) and the total water bulk volume (Bvw). The GWC is also defined using a synthetic resistivity log, R0 and the relative resistivity discriminator curve (RRD) derived from the simple Archie's equation and following the R0 and true formation resistivity log separation.
These techniques have been successfully applied on the “B” reservoir section of a major gas field to detect the true GWC and to prove the presence of movable fluids. The results were successfully calibrated by well test and production logging results.
As demonstrated in the field case discussed in this paper, the findings of this study have important implications for hydrocarbon maturation assessments, field reserves evaluation and consequently the field development strategy.
Deep Gas Potential of Onshore Bahrain Field
Authors: Bugti Muhammad Nawaz , Mukhtar Abdul Nabi , Gaviria William , Nimmagadda Shastri 
Published: January 2010

AbstractBahrain Island is surface expression of a large anticline at depth - the Awali Field. It is one of the oldest producing fields, since 1932, in Middle East. Known producing reservoirs are in Cretaceous and Jurassic. In 1980s, E & P companies in Middle East started looking further below known reservoirs and there was regional success in Paleozoic Unayzah and Khuff Formations, which opened up new exploration frontiers in deeper gas. By late 1980s recognition of Paleozoic petroleum system started in Middle East. Discoveries made in Devonian reservoirs in Bahrain, Saudi Arabia & Turkey; Ordovician reservoirs in Jordan, Carboniferous reservoirs in Syria, and Silurian & Ordovician reservoirs in Iraq.Authors attempted examining and assessing 325 Sq Km of 3D seismic and 400 line km of 2D seismic data, with six deep wells. Considerable Paleozoic section is deposited at Awali field and the anticlinal structure continues well into it, thus forming a basis for exploring an entrapment potential as deep gas play. Horizons interpreted below, producing Khuff and Unayzah, have numerous potential structures and their associated reservoirs in Jubah, Jauf, Tawil, Ra'an, Hanadir and Saq formations. The potential source rocks, such as Qusaiba Shales, also lie within Paleozoic section. Jauf reservoir of Devonian age is found to be gas bearing, and it needs appraisal and development. Fault Trap play anticipated for Jauf and below reservoirs. Its analogue has proven successful on the flanks of Ghawar structure in Saudi Arabia. Seismic data interpretation suggests some stratigraphic truncations, in lower parts of Paleozoic section and on the flanks of its structure, which in turn create a stratigraphic play. Considering high potential of hydrocarbon accumulation in Paleozoic, further exploration efforts are needed and authors initially propose new seismic acquisition campaign specially designed for imaging deeper plays in Awali.
A Completions Roadmap to Shale-Play Development: A Review of Successful Approaches toward Shale-Play Stimulation in the Last Two Decades
Authors: Chong King Kwee , Grieser Bill , Jaripatke Omkar , Passman Andrea 
Published: January 2010

Abstract
Almost three decades have passed since the early exploration of the north Texas, Barnett Shale. The Barnett serves as an example study for the shale lifecycle. Operators in North America have used the Barnett-shale development as a roadmap for the exploration of new shale plays like the Marcellus, Haynesville, and Eagleford. Each new shale play is unique in nature with respect to geologic setting, lithology, and production mechanism. It is useful to have a defined strategy for the discovery, development, and decline phases of each individual shale play. The roadmap to shale well-completion designs should include the following key factors: Fracability: capability of the reservoir to be fracture stimulated effectivelyProducibility: capability of the completion plan to sustain commercial productionSustainability: capability of the field development to meet both economic and environmental constraints
This paper reviews the evolution and development of completion practices of the major USA shale reservoirs in the last two decades and presents a roadmap for effective completion practices for shale stimulation. The completion roadmap uses the history of 16,000 shale frac stages in the Barnett, Woodford, Haynesville, Antrim, and Marcellus shales. Following the map through specific decision points will alter the path for individual shales. These decision points will be influenced by geologic, geochemical, and geomechanical information gathered along the way. The path toward a commercially viable shale play from the early asset-evaluation phase to late asset maintenance-and-remediation phase evolves from a series of decision trees throughout the process.
Information presented in this paper provides a completion engineer with better understanding of the factors involved in shale-play stimulation and provides a methodical approach to select appropriate and optimum solutions that have evolved during the last two decades.
A Review of the Impact of the Use of Formate Brines on the Economics of Deep Gas Field Development Projects
Authors: Downs J.D.. D. 
Published: January 2010

Abstract
The technical difficulty of constructing deep gas wells makes them costly items on any operator's budget sheet. For this reason there is a powerful economic driver for the operator to use the best available well construction technologies that will deliver a deep gas well at lowest overall cost while ensuring that the well's connectivity to recoverable hydrocarbons is not impeded in any way. In 1995 Mobil was the first oil company to use formate brines as drill-in and completion fluids to improve the economics of deep gas field developments. Since then the formate brines have been used in more than 30 deep gas projects (amounting to at least 140 wells) by major oil companies such as Total, Statoil, BP and Saudi Aramco. These developments have included the deepest reservoir in the North Sea and the largest HPHT gas field in the world. This paper collates and categorises all of the statements relating to the performance of high-density formate brines in deep gas well constructions, as recorded in a number of white papers written by three long-term users of the brines. A review of these statements provides an insight into where and how the formate brines are delivering economic benefits in deep gas field developments. This analysis is complemented by a look at the production performance of two deep HPHT gas fields drilled and completed with formate brines in 2001/02. The cumulative hydrocarbon production from these fields is now already close to or exceeding 90% of estimated recoverable reserves. The weight of evidence, supported by the sustained demand for formate brines in these applications over a period of 14 years, suggests that the use of formates introduces economies and efficiencies into deep gas field developments that are a) worth more in value than the overall cost of owning or leasing the brine and b) more rewarding than those provided by alternative well construction fluids.
Overcoming Drilling Challenges in Highly Fractured HP/HT Formations
Authors: Al-Ghamdi Magid A. , Baggal Zaki , Assiry Ali , Omini Eno 
Published: January 2010

AbstractDrilling in highly fractured, high pressure, high temperature gas fields presents various drilling challenges including loss of circulation, gas kicks and hole instability due to the presence of fractures, reactive shale and abnormally pressurized formations.. The original design of the wells was modified to meet these challenges and improvements have been successfully implemented.. These improvements include changes to the original well design, drilling fluid design and drilling practices and these improvements have reduced the problems that were encountered in the troublesome 16”, 12”, & 8⅜” hole sections.. This paper will discuss the different solutions implemented and other solutions being investigated to eliminate the drilling difficulties encountered while drilling HP/HT formations in deep hole sections.
Productivity Impact from Geochemical Degradation of Hydraulic Fractures
Authors: Weaver Jim , Rickman Richard 
Published: January 2010

Abstract
The generation of hydraulically produced fractures that are kept open by the use of proppants is a key technology that enables economic production from deep gas reservoirs. Much laboratory attention has been given to the study and prediction of the early productivity of wells completed with this method. Interactions of formation fluids and frac fluids with formation rock and proppant can lead to a host of productivity-reducing mechanisms. Frac fluid damage, scaling, proppant conductivity loss, proppant crushing, and proppant embedment are some of the variables studied in short-term experiments. Little effort, however, has been directed towards the long-term study of these mechanisms on fracture productivity in a laboratory setting.
This paper presents the results of extensive laboratory testing aimed at understanding the interaction of water composition, formation composition, proppant composition, temperature, and closure stress that permit the modeling of certain diagenetic reactions that result in accelerated fracture conductivity loss with time. Some experiments demonstrate that, under certain conditions, the impact of diagenetic reactions on conductivity loss can be significantly reduced by coating mineral surfaces with protective organic films.
This work clearly demonstrates that proppants can react with formation minerals and result in creation of fines, reduction in permeability, and loss of proppant crush strength. This chemistry should be used in selecting proppant that will provide the most sustained productivity. Sustained fracture conductivity can also be achieved under certain conditions by the use of organic filming agents.
First Successful Tight Gas Reservoir Completion and Fracture Stimulation in Sarah Formation, Rub Al-Khali Empty Quarter of Saudi Arabia
Authors: Bu-Khamseen Raid , Khakimov Ayrat , Sierra Leopoldo , Young Dustin , Machala Mark 
Published: January 2010

Abstract
Lukoil Saudi Arabia started a tight gas exploration campaign in the Rub Al-Khali Empty Quarter in 2006 and nine wildcat exploration wells have been drilled and evaluated. These prospective tight gas discoveries in the Empty Quarter have occurred in High Pressure and High Temperature (HPHT) horizons at depths between 12,000 and 20,000 feet, where the stress and temperature are extremely high in addition to micro-Darcy levels of reservoir permeability. This has made the exploration activity more challenging.
To overcome the extreme challenges and to help assure the success of the exploration activity, a new drilling, completion, and fracturing strategy was implemented in one of the most recent wells. The synergy of the new strategy steps resulted in the first successful discovery in the Sarah formation.
This paper presents the open hole compartmentalized completion steps, as well as the selective fracture stimulation strategy and challenges that have lead to the first successful tight gas discovery in the Sarah formation.
Saturation Calculation in Volcanic Reservoirs––A Case Study for Haer Jin in PetroChina Jilin Oilfield
Authors: Yang Xing wang , Zhang Dawei 
Published: January 2010

Abstract
The SongLiao basin, in north-eastern China, is one of the largest oil and gas basins in China. The volcanic Reservoir underlying the conventional oil bearing and sedimentary reservoirs of SongLiao basin is proven to be huge gas-bearing reservoirs. One deep gas-bearing volcanic reservoir called HaerJin field in the south of SongLiao basin was found recently. As a result of this new find, a joint study project was initiated to perform an evaluation of all available data from existing and new wells, with the objective of calculating gas in place.
The lithology features of the volcanic reservoir of Haer Jin structure are described and the main problems faced are saturation evaluation. Resistivity based methods for saturation analysis have proven to be unsuccessful for this kind lithology. Based on the study on large numbers of core data and the relationship between CMR T2 distribution and capillary pressure curves, one method which has been employed in the study is the calculation of pseudo capillary pressure curves from CMR T2 distributions, and calculation of saturation from the resulting capillary pressure curves.
In the volcanic gas reservoirs, it is difficult to get the formation fluid saturation and gas-water contact from conventional wireline logging data, because of the complicated volcanic mineral composition and petrophysical properties. For the first time, the FWL (Free Water Level) of volcanic reservoir is successfully estimated based on pressure data analysis, which improves the calculation of fluid saturation based on pseudo capillary pressure curves from CMR.
The accuracy and applicability of this formation evaluation approach was proved by the following new drilling wells. The significance of this study is to open one idea for formation evaluation in unconventional reservoir.
This paper will focus on saturation evaluation of the volcanic reservoir in Ha'erJin of the southern Songliao Basin, PetroChina Jilin Oilfield.
Oman, 27/8" Velocity Strings in Deep and Tight Gas Wells
Authors: Goedemoed P. , Al Muselhi F. , Al Manji A. 
Published: January 2010

AbstractIn Oman, many of the gas reservoirs are deep and rich in gas condensate. The deep gas reservoirs require multiple fraccing to enable economical production. The gas and condensate production of the deep gas field described in this paper started in 1999. Since 2007, liquid loading is becoming a growing issue at current flowline conditions. Although compression is scheduled in 2010, some wells still require smaller tubing sizes to enable stable gas production. At current 9,000 kPa flowline conditions, the gas wells start liquid loading in the region of 160 −190 e3m3/d. The installation of a velocity string (VS) stabilizes the gas and condensate production in wells producing &lt; 200 e3m3/d to as low as 50 e3m3/day. As the production life cycle is extended, velocity strings will increase the ultimate gas recovery. In the year 2008/2009 five VS were installed. Production data is available and helps in understanding liquid loading and the modeling of multi phase flow behaviour in deep gas wells.The installation of VS in the Oman Deep Gas field is challenging with respect to its great depth and materials being used. The first VS was installed in a live well in September 2008. Under-balanced installation was identified to be crucial in preventing formation damage in depleted and low rate wells. Some crucial lessons were learnt and solutions were found for all technical and operational challenges. The VS exceed a depth &gt;4500 mTVD and have ~100,000 lbs string weight hung-off on a single retrievable packer system. It was also the first CR13 P110 string ever been snubbed into a live well. This paper describes the first VS trials done in Oman deep gas field, the inflow/outflow modeling and the main operational challenges encountered.
Successful Application of UBD/MPD Technologies for Reservoir Characterization and Drilling Performance Improvement in Deep Gas Formations—Saudi Arabia
Authors: Jiang Qin , Wu Winston , Viera Paco , Russell Bob 
Published: January 2010

Abstract
The proposed well was planned as a vertical exploratory well, which located in the eastern part of a block in Kingdom of Saudi Arabia. Several wells had been drilled in this area by the same operator. The offset drilling data and information show the targeted formations displayed a wide range of pore pressure and different formation stability from well to well. Therefore, mud systems that were much heavier than pore pressure ECD had been used to drill the reservoir formation in past operations. The concern of the operator was that by doing that the reservoir could be damaged to a point that true characteristic of the reservoir could be disguised, or even worse, the reservoir was hidden.
The primary objective of this well is to characterize Formation A and Formation C and evaluate gas production while drilling. UBD/MPD technology was adopted to achieve the planned objective. One of the major benefits of UBD/MPD technology over conventional drilling technology is that UBD/MPD technology has the capability of a prompt and effciant response to the downhole conditions as they occur by simply adjusting the back pressure. This is critical on an operation like this with uncertain formation characteristics, such as pore pressure and hole stability issues.
This paper describes the planning and implementation of the UBD/MPD technique in the 8 3/8” and 5 7/8” section hole of this well and reviews the results of the drilling operations.