bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Screening Methodology for Horizontal Underbalanced Drilling Candidacy
Authors: van der Werken Theo , Boutalbi Said Mohamed , Kimery David William 
Published: February 2016

Abstract
The general benefits of underbalanced drilling (UBD) can be explained in terms of:Drilling performanceReduced drilling problemsIncreased reservoir productivity and recovery by minimization of formation damage.
However, the absence of an easily applicable method to predict which reservoirs will benefit leads to an under-utilization of UBD by the industry. For that reason, the fuzzy logic expert system (ES) introduced in this paper was developed specifically to screen underbalanced candidates with respect to maximizing reservoir performance in terms of productivity.
The ES software considers basic reservoir properties and attributes such as fluid type, drive mechanism, lithology, porosity, water saturation, thickness, permeability, etc. Using algorithms and logic rules, various modules evaluate these input parameters to assess underbalanced candidacy based on the following criteria:The likelihood and severity of formation damageThe overall impact of the damage on productivity and recoveryThe ability to successfully treat this damage with conventional stimulation techniquesThe relative economics of UBD compared to conventional drilling, completion and stimulation techniques
In addition to a description of the ES, this paper discusses several case studies in which the output of the fuzzy logic ES is compared with published successful and unsuccessful UBD campaigns. The results demonstrate that the ES model can accurately predict the suitability of UBD for a given reservoir.

Introduction
UBD is not a new idea. For decades, operators have drilled various geological formations with different drilling fluids designed to exert a bottomhole pressure lower than the formation pressure, thereby allowing oil, gas and water from the formation to flow into the wellbore as drilling proceeds.
One may argue that the benefits of UBD are well documented, however, while few question its value, its perceived issues of safety and complexity - properly managing pressures and production during drilling and completion – are challenging the full acceptance of this drilling technique. In addition to these operational issues, it is more important to realize that UBD is not an economic solution for every formation. Anecdotal evidence suggests that applying UBD in unsuitable reservoirs can lead to more costly and unsuccessful wells. This paper introduces an ES that was developed to aid the successful selection of horizontal underbalanced candidate reservoirs. It is important to note that the proposed ES is specifically built to screen horizontal underbalanced candidates with respect to maximizing reservoir performance in terms of productivity and recovery.
Quantifying Uncertainty in Production Forecast for Fields With Significant History: A West African Case Study
Authors: Castellini Alexandre , Gullapalli Irene , Hoang Viet Thai , Condon Patrick John 
Published: February 2016

Abstract
Understanding the impact of subsurface uncertainties on production responses is an integral part of the decision making process. A more accurate quantification of the uncertainty band around production forecasts contributes to better business decisions. Traditional experimental design workflows, where a limited set of models represent the key uncertainties in subsurface parameters, might be well suited for new field developments. However, when a field has been produced for several years, all models have to be conditioned to available production data in order to obtain meaningful predictions. Data integration and uncertainty assessment of future performance of the reservoir are indivisible processes that cannot be generally addressed by simple techniques.
In this paper we present a method to tackle such complex inverse problems where highly non-linear responses are involved. The goal is to minimize an objective function that stands for the goodness-of-fit of the history-match. The key idea is to use high quality proxies of the objective function to accelerate the search for solutions. An efficient experimental design stage allow for the selection of key parameters while an optimization routine involving Genetic Algorithms (GA) is used to determine the best combinations of parameters. The models that reasonably honor the historical data are selected and provide an estimate of future production. The final distribution of the prediction variables defines the range of uncertainty conditioned to production history. The practicality of the methodology is demonstrated with a study of an off-shore field in West Africa that has several years of complex production history.

Introduction
Quantifying uncertainty in production forecast for a real field with complex history is a difficult task. Monte Carlo simulations coupled with probabilistic inverse theory is in general not practical due to the large number of simulations required. Efficient alternatives involving proxies and various optimization algorithms have been investigated. The fitness of the model to the observed data (history-match error function) is modeled using response surfaces of various nature, polynomial, kriging or spline for instance.
A Tracer Injection-Test Approach to Reservoir Characterization: Theory and Practice
Authors: Samaniego Fernando , Pulido Hector , Rivera Jesus , Camacho Velazquez Rodolfo , Perez Olave Victor Hugo , Martinez Bernardo 
Published: February 2016

Abstract
This paper presents new models and their solutions for the flow of tracers in reservoir, both radioactive and chemical, under constant mass flux conditions, which can be used for the design, evaluation and interpretation of injection test. The models developed consider homogeneous and naturally fractured reservoirs (NFR). For the case of NFR, a transient fracture-matrix tracer transfer is assumed. The models and the solutions acquired include the tracer lost to the matrix inaccessible (dead end) pore volume. The dimensionless groups used in this work resemble as much as possible those used in well test analysis.
Short and long time approximate analytical solutions for these tracer flow conditions are derived, which are useful to validate the general Laplace space solution, and for the interpretation of the tracer response in observation wells.
The solutions presented in this work were applied to real field interwell (observation) tracer responses, allowing the estimation of important fluid and reservoir parameters, such as the radial dispersion coefficient, Dr, and for NFR the average fracture aperture (width) and the block size.
The evaluation and interpretation of a pulse tracer test in a complex naturally fractured and stratified carbonate reservoir is evaluated and analyzed. In this test a chemical tracer Perfluoromethylcyclopentane (PMCP) was used.

Introduction
Tracers are substances that are added to the injected fluid with the purpose of studying the trajectory of the fluids inside a reservoir, as they advance toward the producing wells. A tracer should meet certain characteristics, among others: not interfere with the fluid flow, require a small concentrations and easy detection. Another purpose of introducing a tracer in the injected fluid is to detect the fractures preferential orientation or discontinuities in the reservoir. In any project of fluid injection, the channels of high permeability in the reservoir can quickly establish "short-circuits" for the injected fluid, reducing the efficiency of the process drastically, and in some cases can cause the failure of the project. The field tests with well to well tracer injection and the data analysis with the correct model, provide the possibility for the improvement of the reservoir characterization.
Mature Fields: The Keys to Winning the Marathon
Authors: Saleri N.G. 
Published: February 2016

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

Abstract
The term "Mature Fields" normally evokes connotations of rising costs and diminished expectations, yet the emerging sub-surface, with its utterly different sets of rules and attributes, is changing our paradigms and spurring distinctly higher expectations.
The increasing complexity of well architectures, higher levels of well intelligence and the real-time modality in well placement and field operations, are all products of recent technological advances and specifically the "computer chip". Advanced diagnostics is fast becoming the norm. Do they assure greening of mature fields? What should be our redefined Expected Ultimate Recoveries (EUR's)? Is 90% of Theoretical Maximum Recovery Factor a sufficiently bold target to shoot for? What are the major impediments to achieving higher EUR's for mature fields?
The answers invariably lie in modern reservoir management tenets, in-depth understanding of reservoir fundamentals, due diligence provisions and a wise selection of "smart-technologies" (the key operative word being "wise"). SaudiAramco's portfolio of hydro-carbon assets have, on average, a state of reserves depletion of less than 30%. On the mature end of the spectrum, Saudi Aramco'sAbqaiq Field has already crossed the 80% reserves depletion mark, yet is going strong on the strength of "smart technologies" and provides a real test as to what the smart technology dividend will be in terms of incremental recoveries and reduced costs.
The Darwin LNG Project
Authors: Yates D. , Schuppert C. 
Published: February 2016

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

Abstract
With the start of construction on the Darwin LNG Project in June 2003,ConocoPhillips will set a new benchmark for LNG projects by using aero-derivative gas turbines as drivers for the LNG refrigeration train.
Thirty-five years ago, in 1969, the Conoco Phillips-designed Kenai LNG Plant in Alaska delivered the first commercial LNG exported from the Western Hemisphere to Japan's Tokyo Electric Power Company, Inc. (Tokyo Electric) and Tokyo Gas Co., Ltd. (Tokyo Gas). This LNG operation pioneered the LNG trade to the Pacific Rim, which has grown from less than 1 MTPA in 1969 to more than 80MTPA today. The Darwin LNG Project continues this long-term relationship between ConocoPhillips, Tokyo Electric, and Tokyo Gas with the development of a single train grassroots LNG Plant in Darwin, Australia. This will also be the first LNG project where Tokyo Electric and Tokyo Gas are not just the buyers for the LNG, but also equity owners in the related upstream gas condensate and LPG reserves, pipeline, and associated LNG plant, an indication of the commitment toward a continued long-term relationship amongst the three companies.
The Darwin LNG Project will also introduce several new firsts in the evolution of LNG liquefaction technology. Again, thirty-five years ago, the Kenai LNG Project set the future trend for the LNG industry by becoming the first to use gas versus steam turbines for refrigerant compressor drivers. The Darwin LNG Project will continue to build on this history of innovation and evolution of the LNG industry by being the first LNG plant to use high efficiency, low emissions aeroderivative designed gas turbines for refrigerant drivers. The LNG Plant will also incorporate several other design features to reduce greenhouse gas emissions.
This paper will discuss the history of the commercial development of the Darwin LNG Project that resulted in the execution of a binding HOA and gasfield equity ownership with Tokyo Electric and Tokyo Gas. The various design innovations that will be incorporated into the LNG Plant to reduce greenhouse gas emissions will also be discussed. The paper will provide an overview of the project development activities, including initial contract development, current project schedule, workforce management issues, and the plant handover process.
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.

Abstract
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

Abstract
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

Abstract
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.