bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sequence Stratigraphic Analysis of the Shuaiba Formation: Implications for Exploration Potential in Qatar
Authors: Hohman John , Al-Emadi Ismail Abdullah , Zahran Mamdouh E. 
Published: February 2016

Abstract
Carbonates of the Aptian Shuaiba Formation are important hydrocarbon reservoirs in the Arabian Gulf area. Historically, production has been primarily from fields located along the margins of the Bab Basin, an intrashelf basin that formed during deposition of the Shuaiba. The reservoirs in these fields are progradational packages of platform margin carbonates deposited during the late stages of Shuaiba Platform accumulation. The location of the Bab Basin and the associated productive Shuaiba platform margin trend can be illustrated with an isopach map of the Upper Shuaiba (Figure 1).The Bab Basin is represented by an area of relatively thin, basinal Upper Shuaiba carbonates. An additional area of thin basinal Upper Shuaiba carbonates is located to the west of the Bab Basin and marks the western margin of the Shuaiba Platform. A third area containing a thin Upper Shuaiba section is located to the north of the Bab Basin. This area is often interpreted as an extension of the Bab Basin. However, detailed sequence stratigraphic analysis by Qatar Petroleum and ExxonMobil indicates this area was not a basin, but rather was the result of uplift and erosion that truncates the Shuaiba Platform section. This truncation of the Shuaiba Platform is important as it sets up a new play trend within the interior of the Shuaiba Platform far from the traditional productive trend of platform margin carbonates surrounding the Bab Basin to the south.
A detailed sequence stratigraphic analysis of the Shuaiba reveals a complex internal stratigraphy consisting of relatively thick platform carbonates that thin rapidly into the adjacent basins. Superimposed upon this complex internal stratigraphy is the additional complication of uplift and erosion that has beveled much of the platform section to the north. Regionally the top of the Shuaiba is a recognized unconformity marked by widespread exposure. However, this study further documents truncation of section at the unconformity.
In Salah Gas, a Fully Integrated Project
Authors: Sahnoun S. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
In the mid-Nineties, a joint venture between SONATRACH and BP successfully demonstrated the commercial potential of gas in Southern Algeria, sanctioning the development of the integrated, complex multi-field "In Salah Gas Project",which will bring 9 billion cubic meters of dry gas per year to the markets of Southern Europe.
Key challenges faced by the jointly staffed In Salah Gas project team were to insure the sustainability of 9 billion cubic meters for 13 years minimum in one of the most hostile environments, to put in place the infrastructures to transfer dry gas to the "Centre National de Dispatching de Gaz" (CNDG), 500 km north of the contractual perimeter and finally to meet the high environmental commitments that had been outlined by the Algerian Ministry of Mines & Energy and the SONATRACH and BP management.
The requirement is that the CO2 concentration in the gas stream should be less than 0.3%, significantly below the concentrations present in the In Salah Gas fields, which range between 1% and 9%. The most important aspect of the project is the commitment to non-atmospheric disposal of the 0.66 billion cubic meters per year of extracted CO2 stream that results from the fields production to meet the contracted sales gas volumes. This means that an alternative solution to simply venting would be required.
Storage and sequestration of the extracted CO2 stream is planned within the aquifer region of the hydrocarbon bearing Carboniferous formation adjacent to the Krechba field, the most northerly of the gas fields currently in production since July 2004. Three CO2 injection wells have been drilled with results as prognosed from seismic, providing access into the east and north aquifer reservoir region for storage and sequestration of CO2. The project is now operating one of the largest sequestration and storage schemes in the world.
Another important aspect of the project is the environmental certification ISO 14001, the first one in the world to get this distinction during the construction phase. Another challenge is to sustain this certification for the whole life of the project.
This document provides a case study of one of the first major gas developments where an integrated mitigation plan was constructed in the initial stages of project design, ahead of project sanction. The paper will describe the project and outline the key elements of the development, and the complexity faced by the project team to resolve the environmental, geographical and logistic issues. It will also focus on the options and the solutions that have been identified for managing the key environmental issues of CO2 management and ISO 14001 certification.
Overview of North Field Development
Authors: Al-Kaabi S.S.S.J. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The largest non-associated gas field in the world lies off the Northeast coast of Qatar. The North Field contains reserves in excess of 900 TCF and covers an area of approximately 6000 square kilometers.
The field was discovered in 1971 and an initial drilling program ending in1995 delineated the approximate size of the structure. The first development drilling project of 15 wells was initiated in 1987 with first production occurring in 1991. Today there are four producing platforms and six LNG trains being operated by Qatar Petroleum, Qatargas, and RasGas. Plans are in place to more than double the number of platforms by 2010.
Current daily production is approximately 4.3 BCF per day with 160,000 STB per day of condensate. Projected rates for 2010 are 18 BCF per day with 610,000STB per day condensate.
As drilling has been ramping up so has the understanding of field. Reserve estimates of the early nineties were 273 TCF. Subsequent drilling and more precise modeling had led to current estimates which show the North Field to contain more than 900 TCF plus 23 billion STB of condensate.
Application of new technologies and rigorous application of existing technologies are helping us unravel the intricacies of the North Field and ensure optimal and economic development of this resource.
The fruition of the planning and development work currently underway will see Qatar emerge as the GTL capital of the world and the world's largest producer of LNG.
Wamsutter, A Giant Tight Gas Field: Reservoir Management at a 50 mile by 50 mile scale
Authors: Vines John Ashley 
Published: February 2016

Abstract
Wamsutter is a giant tight gas field covering a 50 square mile area located in Wyoming, USA. The Wamsutter Field contains an estimated 50 trillion cubic feet (TCF) of Gas Initially in place (GIIP). Discovered in the late 1950s, it has to date produced roughly 2 TCF of natural gas and gas equivalent from low permeability (0.01 mD) sandstone reservoirs. BP has a large acreage position in Wamsutter and drills over 100 wells per year in order to efficiently recover field-wide reserves.

Introduction and Development History
Wamsutter was initially developed during the 1970s and 1980s at 640 acre spacing (1 square mile sections) targeting portions of the field with higher reserve estimates and rock quality dubbed the "sweet spot" (Fig. 1).
Field development during the 1990s saw higher density drilling activity in the sweet spot at a reduced 160 acre well spacing. During 2003–04, BP expanded it's position by establishing economic production in previously undrilled leases, resulting in a doubling of Wamsutter acreage. At the same time, BP also received regulatory approval to decrease drilling spacing to 80 acres. Faced with the magnitude of the quadrupling of potential drilling prospects from both the increased acreage and the ability to develop it at a smaller scale, in 2005 the BP Group approved a $2.2 billion investment to develop 500 million barrels of oil equivalent (mmboe) of natural gas resources over 15 years, allocating $113 million for Front End Engineering Design (FEED) technology studies & trials alone.
Fracturing Technology for 4% porosity Libya's reservoir : Application of correct diagnostic and methodology to optimize the fracturing treatment
Authors: Makmun Areiyando , Issa Fathi , Hamed Gadalla 
Published: February 2016

Abstract

Offshore
A drilling program on North Raguba field in Libya has been suspended since the current well's performance in this area was not promising. Well Raguba E-97 in this area was not producing even several attempts such as acidizing, re-perforation and gas lift optimization has been performed.
Petrophysics and core analysis show that the well has 4% porosity and expected very low permeability.
This paper demonstrates a methodical approach in the implementation of hydraulic fracturing technologies on this well. Technical background of fracture design, execution, onsite DataFRAC* analysis which include Mini-Falloff technique to measure transmissibility as well as post job production evaluation were utilized to optimize the result. A brief analysis on pevious treatment performed in this area was also provided and has been used at the design stage.
Mini-Falloff techniques has helped to confirm that even the reservoir has extremely low porosity but has adequate permeability to transfer the flow. Pressure analysis also shown a presence of natural fissures that has been connected by fracturing and contributed to the final production post treatment.
The well flow from 0 to 850 bopd post fracturing treatment. Based on this result, client continue its drilling program and Field Development Plan for Raguba since fracturing technology is proven to be the best solution for this reservoir.

Introduction
Raguba field is located in the western fairway geological trend of Sirte Basin in Libya (central part of Sirte Basin).
The Study of Predominant Production Mechanisms in Naturally-Fractured Rich Gas-Condensate Reservoirs
Authors: Fahimpour Jalal , Dabir Bahram , Piramoon Ebrahim 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
Many studies are recently performed about the fluid flow in gas condensate reservoirs. But the recovery mechanism in a naturally-fractured system of this class of reservoirs needs more investigations. This paper includes the most important mechanisms involve in the production of condensate in a synthetic dual-porosity model which contains a rich gas-condensate fluid. The study focuses on the effect of gravity drainage and gas diffusion mechanisms on the fluid exchange between two mediums: matrix blocks and surrounding fractures network. An inclusive sensitivity analyses are also done on the effect of reservoir properties on these two mechanisms. The simulation results show that the presence of a positive capillary pressure in the matrix system leads to aggregation of condensate in the matrix blocks and hindering the flow of more condensate through the fractures. In the case of moderately permeable reservoirs, the gravity drainage is the predominant mechanism to transfer the condensate from the matrix to the fractures. In such cases, the matrix blocks height is the main effective factor on the performance of gravity drainage; increasing this parameter results in more condensate recovery. Furthermore, the high value of the critical condensate saturation in the matrix may act as a negative factor and obstruct the condensate transfer by gravity drainage. In the reservoirs with extremely tight matrix, gas diffusion has an important role in the fluid exchange between two mediums. This mechanism causes more condensate drop-out in fractures from the gas that diffuses from the matrix. In these reservoirs, increasing the matrix blocks size or fracture spacing as well as decreasing the gas relative permeability in matrix, leads to more gas diffusion and consequently more condensate recovery. These studies express that proper estimation of reservoir properties determines the predominant mechanism in hydrocarbon recovery and gives an acceptable production forecasting.
Multi-Azimuth 3D provides robust improvements in Nile Delta seismic imaging
Authors: Keggin James , Rietveld Walter , Benson Mark , Manning Ted , Cook Peter , Jones Ed , Page Chris 
Published: February 2016

Introduction
Since gas was first discovered in the Nile Delta in late 60's, most exploration programmes have focussed on shallow Pliocene reservoirs, where gas can clearly be seen as bright events on excellent quality seismic data and where exploration success has been very high. The petroleum geology of the deeper pre-Piocene section is fundamentally no different to that seen in the Pliocene, where potential reservoirs consist of sand prone channel systems originating from the Nile. Why then, have we been deterred from exploring in the deeper section? The problem is two fold:Deeper burial and harder rocks mean that reservoir sands and hydrocarbons will be less visible on our seismic data.Pre-Pliocene seismic quality is highly variable and often very poor. (Figure 1) Poor imaging being the result of wavefield distortion though the Messinian layer, attenuation and the presence of complex multiple diffraction noise. These effects are described in the paper.

Can multi-azimuth seismic help improve our pre-Pliocene image?
Multi-azimuth and wide-azimuth seismic are not new technologies; they have been with us for many years in the form of land and ocean bottom cable surveys. The literature is rich with examples of how high-fold multi-azimuth data can produce stunning improvements over their single azimuth 3D equivalents (e.g. Arntsen & Thompson, 2002. Gaus & Hegna, 2003. Rogno et. al. 1999.). We know from theory and case histories that multi-azimuth data will give us improved signal to noise, improved multiple attenuation and improved illumination. In the Nile Delta, we see that the Multi-Azimuth seismic method should address our two main problems of uneven illumination and multiple diffraction noise.
Energy efficient operation of gas export systems
Authors: Noersteboe Vibeke Staerkebye , Bakken Lars E. , Dahl Hans J. 
Published: February 2016

Abstract
The gas transport system on the Norwegian continental shelf (NCS) consists of 7 800 km of pipelines and is the largest offshore network of its kind in the world. Natural gas is processed at treatment plants in Norway, and dry gas exported through pipelines to customers in the UK and continental Europe. These customers have the opportunity to make varying gas delivery nominations, and meeting such sales gas commitments is important.
A major challenge is to operate the network at minimum cost, with minimum environmental emissions, fulfilling variations in contractual nominations and maintaining a sufficient pipeline inventory to provide operational flexibility.
Optimum pipeline inventory and optimum operation of export compressors have been analysed in earlier studies.
The scope of the work presented in this paper is to establish a model for optimum operation of a gas export system, including customer nominations and operation of pipelines and compressor stations. That implies improving system energy efficiency, reducing environmental emissions and maintaining sufficient availability and export deliverability. The model will provide guidelines which will be implemented in planning and operation of the gas export system.
This model is based on analyses of operational data from the gas export system on the NCS. The data are analysed using statistical and simulation software.
The paper describes the established model for optimum operation of the system, where specific power consumption is minimised. A case study which illustrates the use of the model is also presented. Furthermore, the paper reports on a cost-benefit analysis based on the established model.
Development of the Adriatic LNG Terminal Deep Casting Basin Construction Site
Authors: Wesselink Bryan , Tokyay Bora 
Published: February 2016

Abstract
The world's first bottom founded offshore liquefied natural gas (LNG) storage and re-gasification terminal is under development by affiliates of Qatar Terminal Limited, ExxonMobil and Edison for installation in the Northern Adriatic, 15 km east of Porto Levante, Italy. This paper will describe the unique challenges faced and effort undertaken to locate and transform a casting basin to a world class construction and integration site, including removal of the earthen wall prior to tow-out of the terminal.
The concrete gravity based structure (GBS) terminal enclosing two 125,000 m3 LNG tanks and supporting 8 bcm re-gasification facilities will measure 180 meters by 88 meters and be located in 29 meters of water. These dimensions as well as proximity to Porto Levante lead to selection of the casting basin in the Spanish Bay of Algeciras as the construction and integration site. The site is under development by the Algeciras Port Authority for use as a container port, and therefore did not have the infrastructure needed to build the terminal. This paper will provide the basis for how parameters such as size, depth, layout, water and electricity supply, accessibility, dredging requirements, lease requirements, availability of workforce, and capacity for growth were established to result in an effective construction and integration site. Some of the execution technologies used for this terminal, such as removal of the earthen wall, installation of re-gasification facilities and installation of the LNG tanks will also be described.
The conclusions drawn in this paper can be utilized for upgrading of an existing construction site, or development of a Greenfield site into an effective facility for future GBSs, floating structures, or large scale construction and integration projects.

Definitions:
m: meters
mt: metric tons
GSCM: giga standard cubic meters (billion cubic meters at standard pressure)
LAT: Lowest Astronomical Tide
APBA: Algeciras Port Authority
ALNG Terminal: LNG Terminal built by Terminale GNL Adriatico srl

Background
Adriatic LNG Terminal, the world's first offshore liquefied natural gas (LNG) receiving, storage and regasification terminal is under development by affiliates of Qatar Terminal Limited, ExxonMobil and Edison for installation in the Northern Adriatic, 15 km offshore just East of Porto Levante, Italy in 29 m of water.
Evaluation of Deep, Low Frequency Acquisition Techniques on Deep Target Imaging
Authors: Norris Michael W. , Johnson Marvin 
Published: February 2016

Abstract
A suite of air gun configurations was tested in the Gulf of Mexico using a MEMS based OBC acquisition system. One advantage of this acquisition system was the significantly improved low frequency response of the sensors and instrumentation. The improved low frequency response allowed the response of the air gun configurations to be characterized to 1 Hz and below.
The data from the various air gun configurations were analyzed by comparative analysis between the air gun configurations, by analyzing the phase coherence within each of the tested configurations and by examining low-passed versions of brute stacks. The results from the three methods appear to support one another with the conclusion being that conventional air gun sources generate recoverable energy above 5 or 6 Hz. In the area where the test was conducted, coherent energy from the air gun sources could be identified at 11 to 12 s TWT for frequencies above 6 Hz.

Introduction
Low frequency (&lt;10 Hz) content is very important for imaging deep targets and for inversion. Lack of low frequency content means that deep reflectors are poorly imaged or not imaged at all. Additionally other sources of information must augment the seismic data to stabilize inversions. Traditionally streamer data has limited frequency content below 10 Hz and is quite often deficient in frequency content below 5 Hz.
A suite of tests were conducted in the Gulf of Mexico to characterize the low frequency content of conventional air gun arrays and to investigate changes to traditional air gun technology to usefully modify the air gun signature.
The test utilized a 4C, MEMS based, cabled node style OBC acquisition system. Four 6-km acquisition cables were used for the data acquisition. Three of the cables were placed end to end to provide a 720 station, 2D line. The fourth cable was offset 100 m to the southwest of the third cable, Figure 1.
Three Years CO2 Geological Storage at In Salah
Authors: Wright Iain Washington 
Published: February 2016

Abstract
In Salah Gas is a joint venture of BP, Sonatrach and Statoil, which started in July 2004, producing 900bcf/d gas for sale in Europe. The natural gas contains up to 10% CO2, which has to be reduced to 0.3% before the gas is sold. Hence, 1 million tonnes/year CO2 is produced. Rather than vent that CO2 to the atmosphere (business as usual), this project re-injects it into the Krechba Carboniferous Sandstone reservoir via three horizontal wells at a depth of 1,900 metres. CO2 injection started in August 2004 and over the life of the project, 17million tonnes CO2 will be geologically stored at a cost of $100mm ($6/tonne CO2 avoided). This project is an industrial-scale demonstration of CO2 geological storage and is the first industrial-scale project in the world to store CO2 in the water leg of a gas reservoir.
The In Salah CO2 Storage Project is a five-year, $30mm, Joint Industry Project (JIP) with participation from the EU and USA governments. The storage location is heavily instrumented and data is collected and analysed, to monitor the behaviour of the CO2. Objectives are to:Demonstrate to stakeholders that industrial-scale geological storage of CO2 is a viable GHG mitigation option.Provide assurance that secure geological storage of CO2 can be cost-effectively verified and that long-term assurance can be provided by short-term monitoring.Set precedents for the regulation and verification of the geological storage of CO2.
A key part of the monitoring programme will be the deployment of a novel permanent seismic array, allowing frequent, real-time imaging of CO2 migration through the storage formation. This will provide a benchmark against which, alternative technologies can be evaluated. This paper will share results to date of the ongoing CO2 monitoring project.