bluuebunny/crossref_metadata_2025 huggingface dataset:
Egyptian LNG - The Value of Standardisation
Authors: Redding P. , Avidan A. , Quails W.R. , Hernandez R.
Published: February 2016

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

Key decisions at the beginning of any grassroots LNG project critically impact the ultimate success of the project. The variables to consider are numerous but from a high-level perspective, commercial variables such as available gas reserves, finance ability, corporate objectives and market penetration must be considered in combination with project related variables such as schedule, capital expenditures, and life cycle costs. The ultimate objective is to develop a strategy providing the highest rate of return to the owners whilst taking full account of the risks that can be managed by the owners.

Shipping logistics, pre-investment for expansion trains, safety and environmental impact, technology selection and EPC contracting strategy all come into consideration early on in the process. One of the factors that most shape a LNG project is train capacity. Given the importance of economies of scale, the LNG train size that is chosen, along with the associated refrigeration turbine/compressor configuration, is a key decision that impacts almost all other variables. However, since the train capacity impacts so many project factors, the correct choice for one project is not necessarily the correct choice for another. The unique challenges that each project faces must be considered in order to arrive at the best decision for a given project.

This paper draws on the experience of the Egyptian LNG project which is one of several grassroots projects started in the 2000's that remained with the nominal train size of 3.6 MTPA that became standard in the last half of the1990's. It should be noted that 3.6 MTPA is an annualized FOB rate - the actual PFD rate or design rate of the facility is over 4 MTPA. Some other contemporary projects have designed at 5 MTPA and one recent project has announced a 7.5MTPA train. Is it possible for smaller trains to compete in today's LNG business?

The overall strategy for the Egyptian LNG project has been to standardize on the design developed for Atlantic LNG Trains 1–3. In this paper, we will provide an evaluation of the key considerations leading to this strategy and show that highly competitive capital costs can be achieved with smaller trains whilst also significantly reducing project schedule and minimizing owner risk.
Reservoir Simulation Study for Enhancing Oil Recovery of Tipam Sand -2 of Geleki Field, Assam, India
Authors: Vij Rakesh Kumar , Naudiyal Mahendra Prasad , Mandal Dipak
Published: February 2016

INTRODUCTION:

Geleki Oil & Gas Field that covers an area of about 25 sq. km. was discovered in 1968. The main hydrocarbon bearing formations are Tipam Sandstone of Miocene age, Barail of Oligocene age and Kopili of Eocene age containing all together of 35 sand layers (Fig-1). As on 01.07.2007, the field has OIIP 127 MMt in PD category and Ultimate Reserves of 32 MMt in PDD categories. The field has so far produced about 12.60 MMt of oil.

The Tipam sandstone is further subdivided into six layers i.e. TS-1 to TS-6 (from top to bottom). Among these layers, TS-2 is one of the most prolific reservoir in Geleki Oil & Gas field. It is about 200m thick comprises predominantly thick sandstone with intervening thin siltstone/claystone/shale layers of about 1 -10 m thick. The sandstone is generally dirty white to grey, moderately hard and compact, sometimes friable, fine to medium grained, sub angular to sub rounded, moderately sorted and occasionally calcareous.

Though the TS-2 sand is developed in entire Geleki Oil & Gas field, hydrocarbon accumulation is observed only in few blocks namely U & T. Out of these blocks commercial production was established only in U and T blocks and present study is confined to these blocks in South-West part of Geleki Field.

As on 1.07.2007, oil production rate is 130 tpd through 5 oil producers. The Gas Oil Ratio (GOR) is 100 v/v and water cut is 20%. The cumulative oil production is 1.138 MMt, which works out to 15.66% of 7.27 MMt of proved OIIP. Fig.-2 shows the performance of TS-2 Sand of Geleki Field. The R/P (years) ratio of the sand is 16. The sand is under water injection @ 300m3/d through five injectors and cumulative water injection is 0.780 MMm3 (Fig.-3). The initial reservoir pressure was 261 ksc with a saturation pressure of 179 ksc. The present reservoir pressure is around 120–140 ksc. The reservoir is operating under partial aquifer support.

OBJECTIVE:

The main objective of the present study is to review the performance of the TS-2 sand in order to see the effect of ongoing water injection on pressure-production history as there is continuous drop of pressure of producer in spite of continuous injection. Study will also review future exploitation strategy leading to increase in oil recovery through redistribution of water injection and additional inputs in the form of producers / injectors.
Challenges of Natural Gas Utilization in Nigeria
Authors: Iwuanyanwu Henry Uche
Published: February 2016

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

Nigeria is endowed with abundant Natural gas resources, which in terms of energy, is in excess of the nation's proven crude oil reserves. Development and utilization of Natural gas is becoming a major concern in terms of primary energy worldwide due to its abundance, flexibility and combustion characteristics. This study looks at the challenges facing natural gas utilization in Nigeria and solutions and proposed. These challenges includes: Terrain difficulty in the Niger Delta which hinders the gas gathering process, insufficient gas facilities, for gas. Lack of regional and International markets, lack of existing interconnecting pipelines, political and economic issues. The solutions to these include: creation of export oriented Natural gas project which will create regional and international market, invention of new physical incentives for natural gas utilization. Commercialization of Natural gas will increase the nation's GPD.
Integrated Reservoir Modeling to Maximize the Value of a Large Sour-Gas Field with High Concentrations of Inerts
Authors: Huang Nancy Shu-Hui , Aho Gary E. , Baker Burt H. , Matthews Timothy R. , Pottorf Robert John
Published: February 2016

The Madison reservoir in LaBarge Field in Wyoming, U.S.A., is a multi-zone carbonate on the crest of a regionally plunging anticline. It is ~800 ft thick, covers more than 1,000 square miles, includes 4,000 ft of structural closure and holds 22 TSCF initial methane in-place. Methane percentage varies from a high of 23% at the crest to a low of 5% near the gas-water contact, with inerts - CO2, N2, H2S and He - making up the remaining gas. ExxonMobil is the only operator producing from LaBarge Madison and has built a dedicated gas plant to monetize the resource. Current production is 700 MMSCF/d (150 MMSCF/d methane) with 16 crestal producers and two downdip injectors re-injecting 60 MMSCF/d acid gas into the Madison aquifer - one of the world's largest acid gas re-injection projects.

Key project objectives are to:maximize methane production from the existing wells,efficiently operate the gas processing plant, andensure sufficient acid gas disposal capacity such that production is not constrained.

Key reservoir and operational uncertainties include (1) the detailed initial distribution of methane vertically and areally, (2) the impact of the mountainous topography on surface facility flowline hydraulics and producer performance, and (3) long-term injectivity, movement and containment of the injected acid gas within the aquifer.

This paper discusses the integration of reservoir characterization studies, geochemical analysis, surveillance data, reservoir simulation and surface facility network models to optimize the near-term development plan and evaluate potential expansions. Key subsurface results presented include:a potential explanation for the large gas compositional gradient and the history-match approach used to approximate the methane distribution anda method to incorporate temperature-dependent acid gas injector wellbore hydraulics and acid gas viscosity in order to more accurately model pressure and fluid flow.

Integrated reservoir and facility modeling led to selection and implementation of large bore tubing workovers that are, in most cases, more economically attractive than new drillwells.

Field Overview

LaBarge Field is located in Sublette County in southwestern Wyoming, U.S.A., as shown in Figure 1. ExxonMobil owns and operates a majority of the leased acreage, as shown in Figure 2. The primary pay interval is the Madison formation, a deep Paleozoic Mississippian carbonate reservoir, composed of anhydrite and dolomite sequences interbedded with limestone. The Madison reservoir has an original in-place methane resource of 22 TSCF (3.7 billion BOE) distributed over more than 1,000 square miles, and is normally pressured. Methane composition varies from 23% on the crest to only 5% near the gas-water contact.
Safe Marine Access to Platforms in the Southern North Sea
Authors: Jones Alan R.
Published: February 2016

From the early days of offshore oil & gas production in the Southern North Sea (SNS), helicopters have been used for the transportation of personnel to and from platforms.

The increasingly large number of NUI's (Normally Unmanned Installations) coupled with aging installations and increasing well interventions is resulting in a significant rise in NUI workload.

This paper will explain how Shell has developed an innovative marine intervention capability that complements the use of helicopters as the primary mode of transportation in the Southern North Sea.

The marine intervention capability is made possible by the installation of a heave compensating walkway onto a Dynamically Positioned (DP2) vessel. The walkway uses advanced heave-compensated technology to connect a moving vessel with a fixed offshore platform in sea states with a maximum wave height of 4.3 m peak to trough.

Introduction

Shell operates over 50 platforms in the UK and Dutch sectors of the Southern North Sea of which 13 platforms are manned. Historically, helicopters have been used as the primary mode of transportation of personnel to and from platforms.

The widespread introduction of NUI's (normally unmanned installations), where platform maintenance and project work is being liquidated by helicopter shuttling, places a greater demand and reliance on the use of helicopters.

Today in the Southern North Sea (SNS), approximately 75% of helicopter flights are shuttling flights to NUI's.

The increasing number of NUI's, the challenge of maintaining technical integrity on aging installations, the requirement for increasing well work to address sand and water ingress, is resulting in a significant rise in NUI workload.

In addition, the cost of operating helicopters has risen sharply in the last few years.

Finally, the latest generation of low capex NUI's (i.e. tridents and monopiles) are being installed without helidecks thereby relying solely on marine access.
Advances in Wet Gas Pipeline Technology
Authors: Pacheco Jorge Luis , Sisak William J. , Venaik Sunil , Reddy Ramani V. , Robson David R. , Dhokte Atul , Wright Eric John , Pugh Dylan , Curtis Christopher E. , Hickman Scott Ralston
Published: February 2016

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

Subsea pipeline transportation of wet gas over significant distances to an onshore or offshore facility for processing can be a key element in the development of large offshore gas resources. Full well stream carbon steel pipelines offer substantial cost advantages over alternatives such as offshore gas dehydration or pipelines clad with corrosion-resistant alloys. However, such well streams are typically highly corrosive to carbon steel and subject to complex and variable multiphase flow conditions. Realizing the twin objectives of optimum capital expenditure and long-term facility integrity, therefore, requires both a comprehensive flow assurance approach and a robust, highly effective corrosion control program.

This design approach requires close integration of flow assurance and corrosion technologies. Specifically, accurate flow modeling is used to predict the nature of the produced fluids in contact with the pipe wall as a function of the location in the pipe. Corrosion inhibitor qualification testing is then conducted in fluids that simulate the range of anticipated service conditions in terms of both chemistry and hydrodynamics. This paper describes the application of enhanced flow modeling and corrosion testing to more accurately simulate the local top of the line environment for large diameter, sour wet gas lines and to define a comprehensive inhibitor qualification plan and corrosion management program. Operational, facility design and technology lessons learned in implementing these advances in a major project are presented.
3-D Seismic Attributes Applied to Carbonates To Detect Small Faults and Potential Fractures: A Case Study From Kuwait
Authors: Syed Ismail Mohammed , Al-Ajmi Bader
Published: February 2016

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

In general it is difficult to map minor faults and other trace to trace discontinuities hidden in 3D seismic data which has direct bearing on proper reservoir description. Often these subtle faults and discontinuities appear as minor changes in seismic waveform which are not easily correlatable to map them by conventional interpretation techniques. To map these appropriate 3D seismic attributes sensitive to the existence of subtle faults and fractures has been investigated in the target reservoir, the Early Cretaceous (Albian) Mauddud Formation of Raudhatain Field of North Kuwait. Raudhatain field is one of the major fields of North Kuwait. It is a faulted anticlinal dome having two sets of faults and produces from reservoirs in Zubair, Burgan and Mauddud formations. Our main objective of the study was to gain better understanding of and to predict the possible fractures in Mauddud reservoir to improve the structural frame work for effective future planning of development and injector wells based on the findings. Major faults are easily identified at top and base of Mauddud due to large acoustic impedance contrast between Mauddud and clastic units of Wara and Burgan above and below. Smaller faults and possible fractures within Mauddud are difficult to map due to lack of vertical resolution and poor S/N ratio within the reservoir interval. To overcome this various 3D seismic attributes were computed and investigated. Horizon and volume based attributes (Dip & Azimuth, Curvature, Shaded relief, Spectral decomposition and coherency) were used integrating with sub-surface data to arrive at the best possible structural frame-work of the reservoir.
IOR/EOR in South Oman Heavy Oil Fields
Authors: Sikaiti Salim , Regtien Jeroen M.M. , Azkawi Ahmed A.S. , Al Harthi Said , Leith Elaine Sandison
Published: February 2016

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

Several heavy oil fields in Oman are undergoing a rejuvenation using a variety of Improved and Enhanced Oil Recovery methods. The sandstone reservoirs, generally at a depth around 1000 meters, contain heavy oils with API gravities of 18–22, viscosities between 90- 400 cp and exhibit variable reservoir properties of around 20% porosity and 500–2000 mD permeability. Mobility ratios are adverse and all fields demonstrate early water breakthrough and high BSW under primary development. Fields with strong bottom waterdrive are redeveloped with a focus on cost effective infill drilling and water shutoff techniques. Good results have been achieved through segmentation of horizontal well bores with swellable elastomers allowing for targeted mechanical or chemical water shutoff. Innovative infill drilling technologies such as jet drilling and ultrashort radius are either ongoing or in preparation. Further increases in ultimate recovery through in-situ-combustion and high-pressure steam injection are being pursued. The fields with weak or no aquifer support are being redeveloped through waterfloods and chemical or thermal floods. Execution of a polymer project is ongoing with first polymer injection expected in 2008, following a very favourable waterflood response despite geological complexities and adverse mobility ratios. Studies are ongoing into expansion to other areas and a follow-up alkaline surfactant polymer flood. The redevelopment rationalized the existing infrastructure and provides support for waterfloods in satellite fields as well. Redevelopment of a second group of fields is being pursued through thermal methods. Steam injection tests are in final stages of preparation and will start in 2007, followed by phased full field developments. Given the specific reservoir and fluid conditions there are not always analogs and several of the developments pose unique challenges. The paper will present a status overview of several waterflood, polymer and thermal projects as well as key challenges and solutions.
Wamsutter's Integrated Seismic Program-Transforming Land Seismic, From Data Acquisition Through Interpretation and Analysis
Authors: Ramkhelawan Rosemarie T. , Hicks William Alan , Bruce Colin T. , Cooper Craig W. , Hornby Brian , Hornbeck James A. , Wardhana Ricko
Published: February 2016

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

The US Onshore Wamsutter Field Development Team executed two seismic field trials in 2006: a borehole seismic field trial and a cableless surface seismic field trial. The borehole seismic field trial consists of a 4-well crosswell tomography program, and acquisition of a massive 3D VSP with 8000 ft of 3C receiver tool deployed in the wellbore and 6000 surface vibroseis source points. The surface seismic field trial is the world's first deployment of the FireFly cableless seismic acquisition system, with 8300 3C digital sensors deployed, and 7200 explosive source points. These field trials were designed to increase seismic resolution, improve imaging and identification of higher porosity zones, and increase fault and fracture detection, with the ultimate goal of optimizing field performance. The data that was previously available for interpretation had a dominant frequency of 25 Hz, which allowed us to image reservoir thicknesses of greater than 50 feet. The producing reservoirs have much lower average thicknesses, which have been targeted with the new higher resolution crosswell, 3D VSP and dense surface seismic data. Rock properties understanding of the Wamsutter reservoirs has been fundamental to well-to-seismic calibration and interpretation and analysis of the seismic datasets. Seismic forward modelling has been undertaken to calibrate the seismic responses, as part of a larger integrated effort to understand porosity and lithology responses and fracture anisotropy. Field acquisition presented many challenges which were safely and successfully overcome. The crosswell data has resolved reservoir thicknesses of less than 20 feet. Frequencies from the 3D VSP are better than historically recovered in surface seismic data. This integrated borehole/surface seismic approach has allowed us to better understand the seismic responses and calibrate rock properties to different levels of seismic resolution. The Wamsutter Seismic Field Trials is a true success story worth sharing globally.
Do Fluid Compositions and Reservoir Pressure Tell Us the Same Thing About Reservoir Segmentation?
Authors: Gong Changrui , Bunney John R. , Osborne Mark , Zhou Joe , Caruthers Dan , Barwise Tony , Chen Zhangxin
Published: February 2016

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

A multitude of reservoir fluid parameters (pressure, GOR, molecular composition, etc.) are usually available for reservoir segmentation interpretations. These parameters are controlled by multiple reservoir processes including, but not limited to, reservoir charge/filling, fluid mixing through darcy flow/advection/diffusion, gravity segregation, biodegradation, fractionation, and differential leakage. The time scales for these processes to operate in reservoirs will be the key to understanding the relative significance of fluid data to reservoir compartmentalization studies. Numerical simulation provides us a platform to put these reservoir processes to test. Validation and prototyping of the miscible fluid mixing simulation have generated results consistent with analytical solutions and other numerical simulations (Smalley et al., 2004). Preliminary results from simulation for simple geometrical reservoir models suggest that pressure equilibration is the fastest and is several orders of magnitude shorter in time scale than density/composition through convection or through diffusion processes. Thus same pressure gradients do not necessarily mean that fluids have equilibrated in composition in reservoir compartments. We may need to attach different degrees of significance to pressure and fluid compositional data in reservoir segmentation assessment. Field case studies will be presented to apply the fluid mixing simulations to explain fluid data distribution and composition variations. This study will reduce the uncertainties associated with reservoir compartmentalization interpretation using fluid property data and help to optimize oil field development and production.

REFERENCES

Smalley, C., England, W.A., Muggeridge, A., Abacioglu, Y. and Cawley, S. (2004) Rates of reservoir fluid mixing: Implication for interpretation of fluid data. In: Cubitt, J.M., England, W.A., Larter, S. (Eds.), Understanding Petroleum Reservoirs: towards an Integrated Reservoir Engineering and Geochemical Approach. Geological Society, London, Special Publications, 237, 99–113.
Development of highly contaminated gas & oil fields, breakthrough CO2/H2S Separation Technologies
Authors: Klaver Theo C.
Published: February 2016

Description

Shell Global Solutions International B.V ("Shell") has been involved for many years in the development of new technologies to separate CO2 and H2S from highly contaminated natural gas streams. This program has been significantly accelerated in recent years and major milestones have been achieved. The program focuses on technology solutions that are critical to develop (stranded) contaminated hydrocarbon gas and oil fields.

Several key technical challenges in the development of highly contaminated gas & oil fields have been overcome with new technologies developed by Shell. These challenges include: contaminant separation at minimal energy consumption and losses at minimum capital investment.

This paper will present these challenges and introduce new technologies that can help to reduce project development cost by as much as 40% compared to conventional technologies

Application

External studies (Steiner, 2005) estimate a global (recoverable) resource of some 500 B boe (= 3000 tcf), as per bar chart figure 3 below, of gas that is 'contaminated' by the previously defined levels H2S and/or CO2. These resources will require specific technologies to develop these fields economically. The bulk of these resources are in the Middle East, Canada, CIS, Asia and Australia. In general, one could say that the predominantly H2S contaminated fields can be found in the northern Americas (Canada), the Middle East (Abu Dhabi, Kuwait, Oman, Saudi Arabia, Qatar), and the Caspian regions (Kazakhstan, Russia). The indicated size exclude resources that could be accessed via H2S / CO2 Enhanced Oil Recovery (EOR).

The application of the newly developed technologies will be in the area of contaminated gas fields. With new technologies highly, contaminated gas fields can be economically developed to remove the contaminants from the hydrocarbon gas and re-injection of the contaminants. Since conventional technologies become less economic at increasing percentages of contaminant, the new technologies are specifically targeted at high concentrations of contaminants (>30%). The new technologies aim for efficiencies above 85 %, where efficiency is expressed as a percentage of hydrocarbon sales gas divided by the hydrocarbon feed stream. (Losses are due to fuel gas and hydrocarbons left in the contaminant stream)
A New Method In Well Test Interpretation Using Temperature Transient Analysis For Gas Wells
Authors: Bahrami Hassan , Siavoshi Jamal
Published: February 2016

Interpretation of temperature logs has been done successfully in wells to identify water or gas entries location, detect casing leaks, and evaluate cement placement. This paper shows how knowledge of the Joule-Thomson cooling effect and frictional heating effect can be applied for well test interpretation.

Many analysts rely on pressure derivative curve to diagnose wellbore storage period and radial flow regime on pressure transient data. However, there are field examples that flow regimes can't be accurately determined.

During transient tests, both pressure and temperature are changed depending on downhole flow rate. In gas producing wells, Joule-Thomson cooling and frictional heating effects are the main dynamic factors causing flowing bottomhole temperature to differ from the static formation temperature at that depth. When a gas well is shut in, JT cooling effect is vanished and this causes a sharp increase in sandface temperature. As effect of WBS ends, wellbore temperature gradually cools down due to heat conduction with near wellbore region.

This paper demonstrates a new technique for determining end of wellbore storage in pressure build-up tests for gas producing wells using temperature transient data. Application of this robust technique was demonstrated using three gas wells in which both temperature and pressure transient data were analyzed for more accurate welltest interpretation.

Introduction

In pressure transient tests [1], the early portion of the well test data is usually affected by the wellbore storage effect and might be influenced by skin[2] and reservoir permeability.

The wellbore storage effect delays the formation pressure response and distorts the early portion of pressure transient data. Diagnosing of the radial-flow regime is crucial to quantitative interpretation since it provides values for permeability and skin. Unit slope and the plateau on the pressure derivative curve as well as Horner plot are usually used to identify pure wellbore storage and radial flow regime as shown in Fig.1. The interpreter's first task always is to identify the unit slope line and derivative plateau to identify flow regimes [3].
Multi-Disciplinary Reservoir Description to Characterize Connectivity in a Complex Minibasin Fill: an Integrated Approach at Holstein Field
Authors: Wiseman Terrence Robert , Ballin Paulo Roberto , Lederer Mark C. , Wagerle Roger N. , McCaslin Neal F.
Published: February 2016

Holstein is a BP operated, deepwater oil field located in the Gulf of Mexico. Reservoirs comprise stacked, Pliocene turbidite sands with the field formed by a large, steep, southeasterly dipping, monoclinal structure.

Early performance of the field showed a sharper production decline than predicted by the sanction study. Dynamic simulation of early wells suggested limited drainage acreage confined by baffle regions with limited connection to the larger reservoir. A campaign of surveillance data was carried out. Subsequent drilling indicated the reservoirs, originally modeled in pressure isolation, were experiencing pressure depletion through connections between reservoirs. A major effort was undertaken to recharacterize the reservoir, rebuild the static model and generate new dynamic simulations in order to update the development strategy and develop a mitigation plan.

The sanction case geological model described the reservoir sands as being deposited in a ponded, intraslope, salt basin dominated by thick, amalgamated reservoirs with internal homogeneity and excellent connectivity. The subsequent recharacterization describes reservoir architecture elements composed of sandy sheets and channels that shingle to form genetically related reservoirs. Baffling between geobodies and pressure isolated compartments between some shingles are also recognized. Post-depositional modification of the reservoir further complicates well performance by removing reservoir entirely or reducing thickness. A structural overprint creates deformation bands which appear to reduce well productivity through reduction of effective permeability in the structurally steepest segment of the field. In addition, seismically resolvable faults, originally thought to be sealing, are modeled as having variable transmissibility and allowing cross-flow between the complex reservoirs.

A revised heterogeneity model calibrated with dynamic data allowed greater understanding of well performance variations. The assisted history match approach TDRM(4) was utilized to handle the main uncertainties in the field and reach multiple models with good match to all production and pressure data available. These cases used on prediction allowed analysis of production strategies for optimizing recovery.

The data that guided this model rebuild, the integrated modeling process used and the resulting impacts on the depletion plan are described in this work.

Introduction

Holstein is a BP operated, supra-salt, deepwater oil field development discovered in early 1999 in the northern Gulf of Mexico. The field sits under approximately 4300 ft of water 150 miles south of New Orleans and primarily comprises blocks 644 & 645 within the Green Canyon offshore continental shelf protraction area (figure 1).
HPHT, Low Permeability Fields in South Texas...A Legacy of Development in a Tough Environment
Authors: Sodersten Sandra Sue , Sihi Debasish , Cisar Marilyn Taggi
Published: February 2016

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

For over fifty years South Texas has been a part of Shell's producing portfolio. These fields present a wide spectrum of technical, operational, and regulatory challenges. Current fields are a mixture of legacy properties that Shell has operated since the1950's, small but lucrative new discoveries proximal to existing production, and fields acquired in an asset swap with Total in 2006. Well locations range from rural ranchlands to in- town locations near a major airport. Production is almost exclusively gas and associated condensate from Tertiary aged sandstones in the Wilcox, Vicksburg and Frio formations. Reservoirs are generally high temperature and highly geo-pressured. Most of the reservoirs are considered tight gas sands, with porosities ranging from 9–20% and permeabilities in the 0.01 to 1 md range. Wells generally range from 9000 to 16,000 feet with an occasional well targeting a deeper objective. A five-rig drilling program, drilling 30–35 wells per year, maintains production in these 40+ year old fields. Targets for development include infill drilling, field extensions, and deeper objectives in existing fields. Constant vigilance on cost and innovations in drilling and casing design have been employed to maintain profitability of these projects. Integration of all technical specialties from the geosciences to facilities has been critical to making these difficult operations run successfully. This paper will overview some of the technical and business challenges that we have to meet to continually regenerate profitable development opportunities. Many of the traditional tools and techniques of sub-surface analyses do not work very well in this environment. We will discuss some of the tools and techniques that we have found to be useful. We also plan to discuss how we have established ourselves as the best-in-class in south Texas Operations giving us a competitive advantage.
Seismic monitoring feasibility on Bu-Hasa field
Authors: Marvillet Christophe , Al-Mehairi Yousuf Saadalla , Shuaib Mohamed , Al-Shaikh Ahmed , Desegaulx Pascal , Hubans Christian , Thore Pierre
Published: February 2016

A 4D seismic feasibility study has been performed on carbonate reservoirs of the Bu Hasa field onshore Abu Dhabi. It concludes to the feasibility of the method as a reservoir injection monitoring tool, an interesting result when several recent papers [1] have suggested that 4D seismic may not be applicable to Middle East carbonate reservoirs due to their rock physics characteristics.

2D full wave equation and 3D convolutional modelling approaches have been combined in this study in order to maximize the reliability of the predictions while optimizing the cost effectiveness of the study.

Because the assessment of repeatability noise indicated a realistically irreducible threshold for high resolution 4D surface seismic and a possible limitation for WAG monitoring, a 4D well seismic exercise was simulated which overcame those limitations.

Introduction

The Bu Hasa Field, onshore Abu Dhabi, is a super giant carbonate oil field. The Lower Cretaceous Shu'aiba member of the Thamama formation is the main reservoir with porosity above 30%. This field has been producing since 1963 and production mechanism is involving peripheral water injection and crestal gas and water injection. (Figure 1)

The "monitoring" of this field is essential to optimize the production parameters and the value of using seismic information (4D) as an additional reservoir monitoring tool has been assessed [2]. Although seismic is not always considered as fit for purpose for limestone reservoir monitoring because of the stiffness of the rocks, Bu Hasa field is a favourable case because of the high porosities encountered. (up to 30%) Bu-Hasa oil is light and very compressive; therefore, the mechanical behaviour of the oil is closer to gas than water. This means injected water front movements should be more easily detected than injected gas front (in the oil).
Exploring for Fractures in Tight Gas Reservoirs, North Oman
Authors: Millson John A.
Published: February 2016

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

As gas operator on behalf of the Oman Government PDO has been active in a mature basin for ca 18 years. The traditional focus for gas exploration in the north has been on deep Haima reservoirs. These have been successfully targeted in a proven Haima silicilastic "play fairway" where all the classic play elements have been are recognised and areally defined in a target window of ca 4 - 5km. The approach has led to the discovery and development of a number of significant deep gas/condensate fields including: Barik, Saih Rawl, Saih Nihayda and Kauther. Periodic attempts (ca 5 year cycle) to move out of the fairway area based on a challenge of prior geological models, developed with new insights, have often led to disappointing results. Outside the mature fairway all the play elements (reservoir, charge, structure, seal) are still present but an additional overriding "reservoir recovery" play risk becomes significant. Reservoir recovery captures (at a play level) subtleties in reservoir composition/facies, burial history and charge timing that have a significant overprint on the overall play risk. To manage the "operational" factors impacting reservoir recovery in the exploration arena ongoing work pursues optimising drilling, completion and testing procedures. The presence of an open fracture network in a recent discovery has triggered a possible geological "game changer" with the potential to significantly reduce recovery effectiveness risk and unlock significant additional gas volumes across a large area. With the aid of a number of key indicators (rock mechanical properties, recent flexure, fault orientation and late charge) a working model for the deliberate pursuit of fracture systems in an exploration setting (a "fracture play") is being developed. This workflow in conjunction with optimised operations may allow a redefinition of recovery effectiveness risk.
Data Acquisition and Interpretation Challenges in Deep Gas Exploration Wells
Authors: de Koningh Hans , Walton William , Millson John A. , Skaloud Dieter , Harthy Mohamed Salim
Published: February 2016

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

Exploring for gas and gas condensate reservoirs in Oman has in recent years been focussing on deep reservoirs in the Haima Group. Formation evaluation is becoming increasingly challenging with increasing depth. Abnormal pressure regimes and high temperatures go hand in hand with severe borehole breakouts. These factors result in a difficult logging environment making it hard to acquire a good quality data set for formation evaluation leading to efficient completion decisions. Reservoir compaction and cementation increase with depth and typically the reservoirs that are targeted are characterised by low porosity and low permeability. The calculation of water saturation at low porosity is very sensitive to errors. One porosity unit error in this environment will result in a 30 % – 40 % error in the calculated water saturation. In addition, the porosity system in the Haima Group changes with depth. Micro porosity becomes the dominant porosity system at larger depths and this has significant consequences for formation evaluation. In particular with reductions in the resistivity index, the electrical behaviour changes and residual gas saturation increases. Production testing in PDO's exploration setting invariably involves running a liner, completion and some form of fracture stimulation. Therefore, production testing is expensive and time consuming, putting more emphasis on an appropriate "test or abandon" decision. A good understanding of the range of uncertainty on all available data types and their associated interpretation are essential ingredients for the completion decision. A number of examples from recent exploration wells are shown were production test results are compared with pre-test well interpretations with the aim of capturing the lessons learned and highlighting the progress made in recent years in PDO as well as demonstrating the remaining uncertainties.
Redevelopment Of The Abandoned Dutch Onshore Schoonebeek Oilfield With Gravity Assisted Steam Flooding
Authors: Jelgersma Frank
Published: February 2016

The 1 billion stock tank bbls Schoonebeek oilfield produced 250 million bbls medium gravity waxy oil in the period 1943–1996 from a 20 meter thick sandstone reservoir using nearly 600 vertical wells. In part of the field primary recovery was characterised by early water breakthrough caused by a strong aquifer. In another part of the field limited aquifer support in combination with low GOR led to rapid pressure decline and a subsequent requirement for voidage replacement. Small-scale EOR projects were carried out from 1960 to 1996: hot water flooding; wellbore heating; in-situ combustion; high and low pressure steam drives and soaks. In 1996 exploitation was no longer economic, after which all wells were abandoned and most surface infrastructure was removed.

Today, redevelopment of the part of the field that has limited aquifer support is attractive again by use of up-to-date subsurface and surface technologies.

Detailed reservoir modelling identified steam flooding with a closely spaced pattern of 44 horizontal oil producers and 25 horizontal steam injectors in the bottom part of the reservoir as optimal. This process is called "Gravity Assisted Steam Flooding".

To maximise efficiency, a gas fired Combined Heat-Power plant will generate steam and deliver surplus electricity to the national power grid. Wastewater from a nearby sewage plant will be used to produce boiler feed water. Produced water will be disposed of in depleted gas fields in the area via existing gas evacuation pipelines that are converted to water disposal service. Produced oil will be delivered to a refinery in the region by tying into existing third party infrastructure.

The project will deliver more than 100 million bbls of oil and 120 MW of electrical power. Pending Final Investment Decision planned for end 2007, construction will start in 2008 with the project coming on-stream in 2010.

Introduction

The Schoonebeek oilfield is located onshore in the northeast of the Netherlands (figure 1). It is part of a complexly faulted anticline that straddles the Dutch-German border. The German oilfields Emlichheim1, Rühlertwist and Rühlermoor are part of the same structure.

Figure 1. Location map of the Schoonebeek oilfield

The main productive formation is the lower cretaceous Bentheim sandstone (KNNSP). This is an unconsolidated, clean, well-sorted strand plain deposit. Table 1 gives an overview of the reservoir parameters and the medium gravity oil properties in the Schoonebeek oilfield.
Fast Maturation in a Mature Basin; An Example From a Stringer Discovery
Authors: Al-Rawahi Zuwena , Faulkner Andrew , Matvienko Alexander , Al-Mayahi Najma Mohamed , Boersma Diederik Michiel
Published: February 2016

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

Pre-Cambrian carbonate reservoirs occur at depths between 3–6 km in the subsurface of South Oman. These reservoirs are typically over-pressured, encased in and sealed effectively by thick Ara evaporites and contain sour oil. They have been a focus for exploration since the late 1950s. The discovery in 1976 of commercial oil in these "stringers" opened up the Ara play and PDO has since then been actively exploring for these deep oil reservoirs in the South Oman Salt Basin.

Compared to the more conventional reservoirs in Oman, the Ara stringers are complex and pose challenges both in the sub-surface and to surface facilities design, which typically results in a long lag time between discovery and well hook-up. Following the discovery of the Budour NE field in 2005, we challenged to dramatically reduce the time to develop these reservoirs. Thirty five years on, with surface facilities in place and with several producing fields nearby, it was possible to accelerate the appraisal of the discovery and achieve early oil production.

This was achieved through the formation of an integrated exploration and development team that could capitalise on existing infrastructure and local expertise, and was able to deal effectively with appraisal uncertainties. The team worked on the definition, quantification and planning of the field development. This resulted in additional volumes, an acceleration of appraisal drilling, and the early hook-up of the discovery for extended flow testing in 2007, i.e. 18 months after discovery. The latter is a record within PDO for a deep oil discovery. This hydrocarbon maturation exercise will deliver fast reserves, early initial production and an accelerated full field development.
Improvement Of Human Factors In Control Centre Design - Experiences Using ISO 11064 In The Norwegian Petroleum Industry And Suggestions For Improvements
Authors: Aas Andreas Lumbe , Johnsen Stig Ole
Published: February 2016

Managing Human Factors (HF) in the design of control centres (CC) has become increasingly important in large-scale petroleum projects, because of the impact it has on safety and efficient operations. Integrated Operations (IO) and the "e-field of the future" introduce new ways of working, allowing for virtual teams but raise new risk management issues. In 2006, 22 persons, representing different sectors and actors in the industry were asked about their experiences with ISO 11064. ISO 11064 is the standard "Ergonomic design of control centres" and provides guidance on how to handle HF during design of CC.

This paper presents the present status; summarizing experiences made when applying ISO 11064 in Norwegian petroleum projects and suggest areas of improvements. The purpose of the study has been to assess and improve the standard's usefulness for the purpose of reducing the risks introduced by bad design, and to create new guidelines where such are found necessary.

Results indicate that ISO 11064 contributes positively to structuring and legitimating the HF work. The interdisciplinary approach has proved to be an effective HF risk management tool. Applying the standard gives safer operations; this will reduce risk and allow for increased operative efficiency. However, the study also indicates possibilities of improvement of ISO 11064 in areas such as scope of the standard, organizational issues, work procedures, competence in design and operations, exception handling in a virtual organization, communication to the engineering team and documentation of design results. Thus, additional guidelines and techniques are necessary when designing and managing HF in modern CC.

Several improvements to ISO 11064 are suggested. In particular, a goal-based approach can ensure the standard's future applicability, while accommodating technological changes. A survey is planned to follow up on the results to elaborate the findings in the study.

1. Introduction

"HF (ergonomics) is the scientific discipline concerned with the understanding of interactions among human and other elements of a system, and the profession that applies theory, principles, data and methods to design in order to optimize human well-being and overall system performance"[1]. The main objective of this exploratory study is to map experiences from applying ISO 11064 to CC design in full scale industrial projects, e.g. construction of new offshore installations (oil platforms, FPSOs) and onshore process installations as well as major CC modifications of the same.