bluuebunny/crossref_metadata_2025 huggingface dataset:
Impact of High-Quality Seismic on the Field Development of a Mature Supergiant Cretaceous Carbonate Field - Onshore Abu Dhabi
Authors: Boekholt M. , King R. , Al-Hamedi A. , Al-Shekaili F.
Published: February 2016

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

The first field discovered in the ADCO concession came on stream in 1963 and is one of the largest Hydrocarbon accumulations in the UAE. In 40 years of production about 700 boreholes penetrated the main reservoirs, however virtually no seismic was acquired over the field.

In 2001, the decision was taken to acquire high-quality 3D seismic across the field after extensive field tests to optimize acquisition parameters and after incorporation of the learning's on the 3D seismic imaging in other ADCO fields. The actual seismic acquisition took 2 years over an 1800 km2 area with640 fold coverage in 12.5 m * 12.5 m bins. It resulted in an extremely high-quality dataset. Extreme care was given in processing to preserve amplitudes and frequencies to enable quantitative seismic attribute analysis. The seismic offers the unique opportunity to study a Middle East Carbonate reservoir after 40 years of production at an unmatched resolution of 100 Hz bandwidth at target level at 3 km depth.

Conventional interpretation started in conjunction with advanced seismic analysis (inversion & forward modeling while the data processing was still ongoing. The studies indicate that information on structure, rock properties and fluid effects can be extracted from the seismic to a much greater detail than possible in any other seismic dataset of ADCO. So far, immediate impact on the field development was obtained as:several fault systems were observed and tied to the main orogenetic phases of the Arabian plate; inclusive of the Paleozoic and Proterozoic trends. Faults can be observed on seismic down to a throw of 5 ft and were confirmed by drilling results.depositional geometries and stacking patterns within the main Carbonate reservoirs were detected. They were used to develop new insights into the reservoir depositional cycles;Flat spots at the edge of the field and water-indicating isochron values around water injectors in the main reservoirs strongly suggest that fluid effects appear to be visible. Analysis on well and seismic data indicates that the effects of porosity and fluid change on the acoustic impedance can be separated in the studied Carbonate reservoirs.
Realizing the Potential of Marginal Reservoirs: The Al Shaheen Field Offshore Qatar
Authors: Thomasen Jakob Bo , Al-Emadi Ismail Abdullah , Noman Rashed , Ogelund Niels Peter , Damgaard Anders Peter
Published: February 2016

Introduction

The oil bearing reservoirs of the Al Shaheen field, Block 5 offshore Qatar were discovered in the mid-seventies in connection with appraisal drilling on the underlying North Field Khuff gas accumulation. However, at the time, development of the Lower Cretaceous Al Shaheen reservoirs was deemed unattractive due to their limited thickness and tight nature.

Development of the reservoirs commenced in 1992, when Qatar Petroleum entered into an Exploration and Production Sharing Agreement with Maersk Oil Qatar AS.

This extended abstract presents highlights of the development and describes some of the technological advances, which have been applied to attain a commercially viable development.

Challenges

The giant Al Shaheen field comprises a series of thin, stacked reservoirs, dominated by tight carbonates with more permeable carbonate facies occurring over a limited part of the field. The reservoir sequence further comprises a very thin sandstone unit of variable quality.

Following the discovery of the Cretaceous oil accumulation in 1974, a number of appraisal wells were drilled by various operators and comprehensive studies were conducted at the time in order to establish the feasibility of development. However, well tests in the vertical appraisal wells yielded discouraging results and it was concluded that development was not economically feasible.

The main problem was that the majority of the oil in-place existed in thin carbonates with low permeability. Combined with a relatively high oil viscosity, the vertical wells were unable to sustain natural flow and gave very low rates with artificial lift. Further, the hydrocarbon distribution was identified to be governed by non-horizontal fluid contacts due to considerable lateral pressure gradients in the liquid phases. This made prediction of the extent of the accumulation challenging.

Another difficulty was that the reservoirs covered substantial areas, and development would require a very large number of platforms, each connecting to a limited oil in-place volume. This was further aggravated by the fact that the individual reservoirs did not overlay completely but rather spread over different areas.
Carbonate Rock Typing Using NMR Data: A Case Study from Al Shaheen Field, Offshore Qatar
Authors: Frank Soren , Narayanan Ramdas , Hansen Pia , Allen David Furse , Albrechtsen Troels , Steinhardt Henriette , Raven Madeleine Julia , Fordham Edmund , Bize Emmanuel , Rose David Alan
Published: February 2016

Complex pore size distributions encountered in carbonate rocks have a large impact on the fluid flow characteristics of carbonate reservoirs. Consequently, although nuclear magnetic resonance (NMR) has been frequently used for characterization of clastic reservoirs, it has not been widely applied to carbonates. This paper describes a case study from the Shuaiba carbonate reservoir of the Al Shaheen field, offshore Qatar. Core data from a study well were used to establish an NMR carbonate rock-typing model for permeability estimation. The rock-typing model was verified in the study well with a wireline NMR logging tool.

Core analysis included thin-section petrography, NMR surface relaxivity, mercury injection, porosity and permeability measurements. NMR distributions determined on core were partitioned and linked to pore body size and pore throat size distributions. Several rock types were also defined based on their NMR and petrographic characteristics. To improve permeability prediction in the cored interval of the study well, an NMR-based permeability equation was derived.

The core-calibrated NMR carbonate rock typing model was applied to noncored sections of horizontal wells drilled in the Shuaiba formation having logging-while-drilling (LWD) NMR data to improve rock typing and permeability estimation, thus, providing valuable input data for reservoir modeling.

Introduction

Permeability estimation and rock typing of the complex Shuaiba carbonate reservoir in the Al Shaheen Field is an important element in the development of reliable petrophysical and geological models. Rose et al. demonstrated that facies changes along horizontal wells in the Shuaiba reservoir were captured by the T2 distribution from an LWD NMR tool. The corresponding permeability variation was linked to the facies, and a qualitative determination of the lateral permeability distribution was achieved.
Environmental Impact Assessment of Exploration Drilling in the South Caspian Sea
Authors: Tait R.D. , Parr T.D. , Germano J. , Maxon C.L. , Passmore J.L.
Published: February 2016

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

Pre- and post-drilling environmental studies were conducted for two exploration wells drilled in the Azerbaijan sector of the south Caspian Sea. The two wells, located at water depths of 142 and 720 m, respectively, were drilled with water-based and synthetic-based drilling fluids. The studies were undertaken as part of the defined environmental, health, and safety management programs negotiated within the Production Sharing Agreements, and focused on surface sediments located within 1.2 km from each well. Post-drilling studies ranged from three months to three years following well completion. Co-located samples were analyzed for metals and hydrocarbons, including linear alphaolefins; and benthic community parameters, including species density, abundance, and biomass of major taxa. Eight months after drilling ceased, results for the well in 142m of water supported the Environmental Impact Assessment report, confirming that settled cuttings and muds were limited to400m distance, and that significant re-colonization of benthic infauna had occurred around the well site. Cross-sectional photographic images of the seafloor showed evidence of significant oxygen demand and settled cuttings within 50m of each well. Chemical and biological results for the well in 720mwater depth, sampled three months after well completion, are discussed in relation to the observed recovery processes.
More Than 30 Years Experience With F(P)SOs and Offloading Techniques
Authors: Lanquetin Bertrand
Published: February 2016

Disclaimer

The information given in this paper is based on archives, interviews with people, etc. and is given to the best of our knowledge. There may be some minor inaccuracies on the dates and on the information given for which we would like to apologize in advance to the readers of this paper and to the providers of the equipment and installations mentioned here.

TOTAL E&P Branch, present today in more than 43 countries and producing 2.6 Mboe/d, has steadily become an important player in the field of Floating (Production) Storage and Offloading facilities, key to several oil and gas field developments. The experience described below is the cumulated experience (upstream) from TOTAL, Petrofina and Elf Aquitaine who successfully merged in 1999 and 2000 to form TOTAL.

As the reader will rapidly notice this experience is extremely rich and diversified and includes many maiden installations as well as technology breakthroughs.

Some of them:–The Ifrikia (Ashtart field Tunisia 1973) was the first FSO (Floating Storage Unit, converted tanker) permanently moored by a rigid yoke on a CALM buoy, followed in 1978 by the Ifrikia II, the first purpose build FSO barge.–The Frigg flare (North Sea 1974) was the second Articulated Column. It followed an experimental articulated column installed in 1967 in the Bay of Biscay.–The first Ready Made Dolphin was installed on Quinfuquena (Angola 1979).–In the same year the first two turret type CALM buoys were installed on Mayumba (Gabon 1979), then Kole (Cameroon 1979).–Three CALM type buoys of a new design using self lubricating bushing in lieu of main roller bearing, were ordered for Rospomare (Italy 1981), ABK (U.A.E 1981) and Victoria field (Cameroon 1982).–The Licorne Pacifique converted tanker on Palanca field (Angola 1984) was the third CALM soft-yoke (the first one was in 1981).
How Clean is Clean? Is It Still a Debate?
Authors: Garland Emmanuel
Published: February 2016

Environmental Regulatory Framework for E&P activities has dramatically increased during the last decade, and no one contests that environment did benefit from the measures taken. But the development of the regulatory framework in many countries, the constraints it creates, raise the question on where the cursor should be fixed.

The latest developments of the regulatory framework show that:expectations from stakeholders increase, for all compartments of the environments, and everywhere in the world;the gap between constraints in countries with a long record of environmental regulations and the others is increasing;but countries which set up environmental regulations for the first time tend to take even tougher measures than the ones implemented in the countries with a long record of environmental regulations;the dialogue between stakeholders, competent authorities and E&P industry is worth the effort to promote it; it requires a change of perspective from all participants.

In that context, the debate on the ultimate goal(s) to pursue, and on the intermediates ones has usually been a source of misunderstanding between the regulators and industry, and it is only very recently that new, more pragmatic, ways to approach a common understanding of how clean is clean appeared, at the light of both the development of better monitoring or predictive tools and of the debate on zero discharge, zero harm to the environment.

Introduction

Environmental regulatory framework for Exploration and Production (E&P) activities has dramatically increased during the last decade. Not only western countries with long industrial record have set up tougher rules, some based on existing ones (e.g. the new requirements of the National Pollutant Discharge Elimination System – NPDES, in the US), others on new environmental approaches (e.g. OSPAR set of Decisions and Recommendations adopted between 1998 and 2001 which dramatically changed the way some environmental issues are dealt within the North Sea) (1–6), but countries with so far limited or no environmental framework have developed – or started to develop - environmental regulations, some of them with even tougher constraints than the ones enforced in western countries ones (e.g. Nigeria regulations on drilling fluids and disposal of drill cuttings).
A New Dawn for CO2 EOR
Authors: Espie Tony
Published: February 2016

A range of techniques have been developed to improve the recovery efficiency of oil reservoirs. Of these, gas injection is currently the second most common EOR process after thermal methods that is practiced on a material scale with some 250 mbd directly attributable. Initial exploration of gas injection focused on use of a hydrocarbon injectant. However, competitive sales markets for hydrocarbon gas led to the identification of CO2 as a potential injectant.

There is now over thirty years experience with the injection of CO2 for Enhanced Oil Recovery. Although initially developed as a means to improve oil recovery, there is renewed interest in the potential for CO2 EOR as an option to reduce global emissions of Greenhouse Gases. This may lead both to a significant expansion in the level of application as well as to some significant changes in the way in which CO2 EOR is applied.

Introduction

Many areas of the world are actively implementing gas injection to maximise the potential of extensive oil reserves. A successful gas flood requires two key criteria be satisfied. Firstly, the injected gas must be able to mobilise additional oil. Secondly, the flood must be able to sweep the mobilised oil to producers.

Additional oil may be mobilized in two ways. Firstly, gas may be able to access parts of the reservoir that have been bypassed by water. Second, gas may enable some incremental recovery from those parts of the reservoir already swept by water by virtue of the fact that the residual oil saturation to gas is usually somewhat lower than for water.

Many of the current gas injection schemes operate near to miscibility conditions to mobilise the maximum amount of incremental oil. The injected gas is often used in combination with water in order to get the joint benefits of mobilising oil with the miscible gas while using water to sweep mobilized oil to producing wells.
CO2 Capture and Storage: Contributing to Sustainable World Growth
Authors: Espie A.A.
Published: February 2016

The potential to exacerbate or accelerate climate change as a consequence of burning fossil fuels has received considerable international attention in recent years. The Kyoto Protocol emerged as one response to initiate first steps towards stabilisation of atmospheric concentrations of CO2.It is clear that there is no one single technology that can lead to stabilisation in the timeframe that appears to be required. Large-scale implementation of capture and storage of CO2 is being considered as a potential option that could make a material contribution to a portfolio of options for the stabilisation of atmospheric concentrations.

A number of hurdles require to be overcome before this technology will be widely applied. These include i) significant reductions in the cost of capture of CO2 from combustion processes, ii) acceptance that geological storage can be a safe and effective mitigation option, iii) the development of commercial mechanisms that enable viable projects to emerge and iv) clarification of a number of regulatory and legal issues.

Introduction

The Intergovernmental Panel on Climate Change (IPCC) was jointly established in 1988, by the World Meteorological Organization (WMO) and the United Nations Environment Programme (UNEP). Its present terms of reference are to:Assess available information on the science, the impacts, and the economics of - and the options for mitigating and/ or adapting to - climate change.To provide, on request, scientific/technical/socio-economic advice to the Conference of the Parties (COP) to the United Nations Framework Convention on Climate Change (UNFCCC).

The Third Assessment Report from the IPCC [1] was published in 2001.This detailed review of the scientific, technical and socio-economic aspects of climate change concluded that there is clear evidence to show that global climate has changed over the last 100 years and that a significant proportion of that change could be attributed to the release of anthropogenic CO2 into the atmosphere during the combustion of fossil fuels.
Project Financing of Qatargas II
Authors: Fleming A. , Minyard R.J.
Published: February 2016

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

In December 2004, the Qatargas II joint venture between Qatar Petroleum(70%) and ExxonMobil (30%) completed the —7.6 billion financing for the integrated project to supply LNG from Qatar to the United Kingdom.

The landmark financing, involving 57 lenders, is the largest ever energy project financing. It provided the funds to execute the complex project which involves the development of offshore wells, production platforms, pipelines and natural gas liquefaction facilities in Qatar; construction of the South Hookimport terminal at Milford Haven in South Wales; and the sales and marketing of the gas by the winter of 2007/8. The financings, which set several new benchmarks in their pricing and other terms, also mark a number of firsts in energy industry project financing. These include:–The first LNG financing where the entire chain from wellhead to terminal has been developed by the same partners throughout and funded through integrated financings.–The largest long-term Islamic project financing.–At 25 years, the South Hook Terminal financing is the longest sterling bank energy transaction without government or mono-line credit support.

The presentation will cover some of the key elements that resulted in the award winning financing including the:–The challenge of financing the entire value chain from wellhead to terminal–Early development of successful Standard Financing Conditions (TermSheet)–Importance of coordinating project agreements and financial agreements–Structuring for future business flexibility–Market reception for Qatar project debt
Portable Test Separator (SEPARATRUCK) Alternative of Measurement
Authors: Ruiz M.A. , Arditi L.
Published: February 2016

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

Exact and reliable production well testing allows to quantify the volumes of fluids produced and additionally to diagnose the anomalies on time to carry out early adjustments in the wells, in order to have a production with the highest efficiency. The Portable Test Separator SEPARATRUCK appears like an economic alternative of measurement in wells production in the Venezuela's Orinoco Heavy Oil Belt. The project consisted on the elaboration of a design methodology, based on studies made in the field that allowed determination of the main faults in the measurement of the production with the traditional test equipments, establishing specific considerations for the design of a new, portable and automated in all its functions measurement equipment. The mass, is the primary unit of measurement and because it is not affected by the changes of viscosity, density, electrical conductivity, pressure and temperature; this parameter turns out to be simplest and at the moment most reliable to measure. For that reason, the prototype will be equipped with two mass flow and density meters, in addition to a radar device able to control different fluid levels configurations; this, in combination with technological improvements of the Coriolis measurers, will provide a wide rank of ability allowing to adapt the configuration of the system, resulting in an equipment able to test wells that produce from different reservoirs (different API gravities) and at variable production rates (different GOR), diversifying the measurement, making flexible and popularizing the equipment. The design calculations were validated by means of numerical simulation, obtaining a portable test separator able to handle upto 2,500 bbl diluted heavy petroleum, with water cuts between 0 and 100%, and a maximum gas rate of approximately 5 MMscfd.
Technology Deployment Model
Authors: Al Wardi Ali , Al Murshidi Abdulsattar Mohd , Edwards Clement
Published: February 2016

A recent health check analysis indicated that a better structure was required to deploy new technology in the company. An Opportunity Framing workshop was held in May 2004 and a team was formed to formulate a new technology deployment model.

The model developed, uses a network of technology passionate individuals organised into Technology Focus Groups (TFG). These groups are multi-function/cross-asset and have members from the Function and the Line. They will be the implementation arm of PDO's technology process. The model also calls for a multi functional leadership group to provide support and nurturing to TFG's as well to act as a decision making body.

The essence of this model is to maintain a balance between the pull and push of Technology. It improves the ability to make decisions, accelerate or stop deployment and redeploy resources accordingly.

Introduction

Roadmapping is a technique that is used by many companies and research organizations to plan for the future. Motorola found that when group of people in the company come together to develop a consensus vision for the future of technology areas that affected their business, this pervasive culture of technology roadmapping enabled them to produce roadmaps that communicate vision, attract resources from business, stimulate investigations and monitor progress.

Opportunity framing or realization process is a powerful and structured approach for defining and understanding an opportunity, it ensures planning the road to success. It facilitates a true dialogue among Opportunity team to disuses several, distinctly different perspectives of the:

Opportunity ("Where are we now?"), definition of its success at several future milestones ("Where do we want to be?") and the different decisions and processes that need to be set to realize the opportunity ("How are we going to get there?")
Some Practical Issues on Real-Time Reservoir Model Updating Using Ensemble Kalman Filter
Authors: Wen Xian-Huan , Chen Wen H.
Published: February 2016

The concept of 'closed-loop' reservoir management is currently receiving considerable attention in the petroleum industry. A 'real-time' or 'continuous' reservoir model updating technique is a critical component for the feasible application of any closed-loop reservoir management process. This technique should be able to rapidly and continuously update reservoir models assimilating the up-to-date measured production data so that the performance predictions and the associated uncertainty are up-to-date for optimization calculations. The ensemble Kalman filter (EnKF) method has been shown to be quite efficient for this purpose in large-scale non-linear systems.

Previous studies show that a relatively large ensemble size is required for EnKF to reliably assess the uncertainty and a conforming step is recommended to ensure the consistency between the updated static and dynamic variables. In this paper, we further explore the capability of EnKF focusing on practical application issues including the correction of the linear assumption during Kalman updating with iteration, the reduction of ensemble size with a simple uniform re-sampling scheme, and the impact of assimilation time interval.

Results from this paper demonstrate that the predictive capability of the updated models can be considerably improved when iteration is used within the EnKF updating. The use of iteration reduces the impact of nonlinearity and non-Gaussianity. However, iteration is required only when predictions are very different from the observed data. We also show that a simple uniform re-sampling scheme can significantly reduce the ensemble size necessary for reliable assessment of uncertainty, in addition to improving accuracy compared to the traditional random sampling method. Finally, we show that the non-iterative EnKF is sensitive to the size of time interval between the assimilation steps. Using the iterative EnKF, results are more stable and more accurate reservoir models and predictions can be obtained even when a large time interval is used during the assimilation. This indicates again that iteration within the EnKF updating serves as a process that corrects the non-linear and non-Gaussian behaviors.
Integrated Geochemical and Basin Modeling Analysis of the Jurassic and Cretaceous Hanifa Hydrocarbon Systems in Qatar
Authors: Guthrie John , Maze William J. , Al-Emadi Ismail Abdullah , Zahran Mamdouh E.
Published: February 2016

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

Organic-rich mudstones of the Tuwaiq Mountain and Hanifa Formations of the Jurassic Hanifa Supersequence are the major source rocks for much of the oil in the Arabian Gulf. An integrated geochemistry and basin-modeling study on these source rocks and their oils was conducted to explain the distribution of petroleum accumulations within the Hanifa hydrocarbon systems of Qatar.

Principal component analysis (PCA) of biomarker and stable carbon isotope data for oils and condensates delineates three major hydrocarbon systems in Qatar: Jurassic Hanifa-sourced oils,Cretaceous Shilaif-sourced oils and,Silurian Qusaiba-sourced condensates (Figure 1).

The biggest contribution to the PCA comes from Factor 1 where 63% of the variance in the data is primarily due to source rock facies variations. Oil-to-oil correlations indicate that the Jurassic Hanifa-sourced oils are present in both Jurassic and Cretaceous reservoirs.

The Hanifa sourced-oils exhibit relative thermal maturity differences between fields and by reservoir age (Figure 2). In general, reservoired-oils(Arab C, Arab D, Araej, Izhara, and Uwainat reservoirs) from the Dukhan, Maydan Mahzam, and Bul Hanine fields have higher relative thermal maturities than reservoired-oils from Al Rayyan, Al Shaheen, and Idd El Shargi. For a particular field, the relative thermal maturity of the oil appears to be related to stratigraphy, with the least mature oil in the youngest reservoir, and oil maturity increasing with reservoir depth. This is best observed in the Idd El Shargi field where the oil is least mature in the Cretaceous Shuaiba and Jurassic Arab C reservoirs and becomes more mature in the older (deeper) Arab Dand Uwainat reservoirs (Figure 2).

The occurrence of relatively higher maturity oils in deeper reservoirs (ArabD, Uwainat, Izhara) suggests that the reservoirs were filled from top tobottom. Figure 4 shows that in the Eastern Salt Province fields, the Hanifa source rock maturity increased from early mature to peak mature since50Ma. During this time, the deeper Izhara and Uwainat reservoirs of the EasternSalt Province fields were charged with higher maturity oils.
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

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.

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.

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

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

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

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

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

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 (<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.