bluuebunny/crossref_metadata_2025 huggingface dataset:
Large Diameter Coiled Tubing Becomes Available Safely Offshore Through a Newly Developed Spoolable Connector: Case Histories and Field Implementation
Authors: Link L. , Laun L. , Nesvik K. T. , Boge H.
Published: December 2007

Coiled Tubing operations in the North Sea are regularly challenged by crane lift capacity limitations when attempting to bring coiled tubing reels onboard. Very often the crane capacity or weather conditions determine the CT size to be used for the application, leading to operations conducted with less then the optimum CT size. The Norwegian sector generally has larger capacity cranes but most operations regularly involve the use of large OD coiled tubing (2.375" or 2.875"). The lengths required can cause logistical problems due to the lifting weights of the CT reels used. Current methods utilised for keeping weights as low as possible involve using so called split reel systems and thin-walled high strength parallel CT strings (i.e. constant wall thickness). While these weight reducing measures have proven themselves for many years now in the Norwegian sector, they can not resolve equipment weight issues in all cases. The joining of 2 or more separate strings together offshore by installing butt welds has been standard practice in the UK sector for many years now, mainly involving CT sizes of up to 1.75". In the Norwegian sector, butt-weld failures have occurred when using larger CT sizes and operators have been seeking a viable option to butt-welding, especially for larger OD CT.

In response to a direct request by the BJ Services North Sea operations departments, BJ Services Coiled Tubing Research & Engineering group in Calgary, Canada have developed and commercialised a LCF (Low Cycle Fatigue) Spoolable Connector to replace offshore butt-welding and resolve weight issues associated with heavy CT reels.
Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition
Authors: Høgnesen E. J. , Strand S. , Austad T.
Published: December 2007

Much effort has been focused on wettability modifying methods to improve the water-wetting nature of carbonates in order to enhance the oil recovery by spontaneous imbibition of water. The use of expensive surface active additives like cationic surfactants of the type R-N(CH3)3+ have been suggested, as well as steam injection. In this study, we will discuss possible wetting modifications of carbonates in relation to potential determining ions present in the injected fluid. Artificial seawater is used as the base or reference imbibing fluid. Outcroup chalk cores of high porosity and low permeability and reservoir limestone cores were saturated with oils with high acid number at residual water saturation to render the cores preferential oil-wet. Spontaneous imbibition tests were performed at different temperatures ranging from 70-130 °C using modified seawater with various concentrations of sulfate, which is regarded as a potential determining ion towards carbonates. Major observations were: (1) Spontaneous imbibition of seawater took place only at elevated temperatures, (2) For the chalk samples, the oil recovery increased beyond the recovery at completely water-wet conditions when the concentration of sulfate was increased 3 times relative to seawater at 130 °C, (3) Reservoir limestone cores also responded with increased oil recovery at 120 °C as the sulfate concentration increased, (4) at lower temperatures, increased spontaneous imbibition was obtained when adding cationic surfactant to the imbibing fluid, (5) The activity of sulfate as a potential determining ion, and thus a wettability modifier, appeared to increase as the temperature is increased. The results show that sulfate is a very efficient wettability modifying agent towards carbonates at elevated temperatures.
Problems Which Can Occur During Coiled Tubing—Case Study: Hassi R'mel Field, Algeria
Authors: Boussa M.
Published: December 2007

Production - Pressure - PLT - RST – GHOST – CBL -Permeability - Porosity - Cement Squeeze - IP

Summary:

A non-rig Coiled Tubing Unit (CTU) cement squeeze technique has been developed and proven since years. This technique does not require that the well be killed. But problems can arrive during the operation and compromise it. For that a study was undertaken on the squeeze cement operation, realized on hassi r'mel field well.

Hassi R'mel field is a gas condensate reservoir with a superposition of three layers A - B - C having very good petrophysic characteristics and a rather significant oil rim in the Eastern and Southern peripheries.

Producing wells were drilled in the Northern part - Central -Southern with two lines of dry gas injection.

Production of water with high salinities disturbed the good production of the wells, which generated negative effects to the gas processing units.

It was necessary to decrease rate of flow of these wells to be able to decrease the volume of water, which generates a loss in the production of gas. In certain case it is necessary to close the well completely.

RST - PLT - GHOST were recorded on these wells to determine the origin of this water influx and a CBL was recorded to see the state of the cement of liners.

Following the results of the operations carried out, a study was undertaken in order to see the method to be used for the optimization of these wells: –Avoid placing a bridge plug for the layer C, because one will lose a good part of production of gas, since this level is more prolific than the other levels.–Isolate the places and perfos which produces water by a cement squeeze.

The purpose of this presentation is to show: –the problems which can occur during operation of coiled tubing; and the reasons of squeeze cement failure.–to show a real case carried out on hassi r'mel field–the advantages and disadvantages of use the coiled tubing.–solutions to adopt to improve the use of coiled tubing.
Case History: Efficient Coiled-Tubing Sand Cleanout in a High-Angle Well Using a Complete Integrated Cleaning System
Authors: Loveland M. J. , Pedota J.
Published: December 2007

As in many oil fields, the primary coiled-tubing (CT) operation in the Kuparuk River Unit on the North Slope of Alaska is a wellbore cleanout. These cleanouts remove produced fines, fracturing sands, scales, and paraffin. As drilling technology advances and wells become longer and more deviated, the process required to clean out these highly deviated wells becomes more complicated. One such case, West Sak Well, is an undulating horizontal well in unconsolidated West Sak sands with a low bottomhole pressure (BHP). During previous attempts with standard cleanout methods, returns were lost during the job and the final results were less than optimal. Post-job reviews of the unsuccessful conventional cleanouts illustrated where previous approaches were insufficient.

This paper describes the use of an integrated cleanout system that efficiently addressed all the challenges of the West Sak Well, which resulted in a successful cleanout returning the well to production. This integrated system approach to wellbore cleanouts was recently commercialized, and this well was the first job using the system in Alaska.
CO2 Capture and Storage in Mature Oil Reservoir: Physical Description, EOR and Economic Valuation of a Case of a Brazilian Mature Field
Authors: Gaspar A. T. F. S. , Lima G. A. C. , Suslick S. B.
Published: December 2007

The mitigation of environmental problems requires both national and international agreements, since they have possible global effects. In nationwide conventions (such as Rio, 92; Kyoto Protocol, 1997), a common conclusion has been the need to reduce greenhouse emissions, especially those due to CO2 from burning fossil fuels. For example, Kyoto protocol has established that industrialized nations should reduce their emissions over 2008-2012 by at least 5.2% compared with the 1990 levels. An alternative USA proposal is based on reducing greenhouse emissions by capturing and stockpiling CO2 in natural sites like oceans, caverns, depleted oil reservoir, etc. This paper presents a physical description and an economic analysis of a project to capture and inject CO2 in oil production and its storage in the depleted oil reservoir located in a mature field in Brazil. The Stella® Software has been used in order to analyze de dynamics of the whole process of CO2 sequestration in enhanced oil recovery, considering each step of the process with its respective energy requirements. The main findings of this have the following benefits: i) reduction in the emission of CO2; ii) extension of the operational life of the reservoir; and iii) improvement and development of technology to promote EOR in mature fields. Results indicate that project NPV is around US$ 3.2 million, what is significant for a small mature field. Additionally, it contributes by removing greenhouse gases (GHG) from the atmosphere by storing 0.73 million tons of CO2 over a period of 20 years. Project feasibility, as expected, was found to be very sensitive to oil price, oil production, and CAPEX.
Capillary Alteration of Shaly Caprocks by Carbon Dioxide
Authors: Chiquet P. , Broseta D. , Thibeau S.
Published: December 2007

The efficiency of the CO2 geological storage process in aquifers and hydrocarbon reservoirs is controlled by several factors. In the case of reservoirs with a shaly caprock, one critical factor is the capillary-sealing potential of the caprock. This potential can be expressed in terms of a maximum storage pressure, equal to the hydrostatic pressure in the caprock plus the CO2 capillary entry pressure in the brine-saturated caprock. It is therefore controlled by the CO2-brine interfacial tension, the water-wettability of shale minerals, and the pore size distribution within the shaly rock.

By means of contact angle measurements, we provide experimental evidence that the water-wettability of minerals representative of shales, such as mica and quartz, is significantly altered in the presence of CO2 under pressures typical of geological storage conditions. Those minerals, known to be strongly water-wet in the presence of oil, turn out to be intermediate-wet in the presence of dense CO2.

We discuss the consequences of such wettability alteration on the maximum CO2 storage pressure, which can be converted into a maximum CO2 height stored in the reservoir. In the case of hydrocarbon reservoirs initially close to capillary leakage, the maximum CO2 storage pressure should be only a fraction of the initial virgin pressure.
Pore- to Field-Scale Multi-Phase Upscaling for IOR
Authors: Lerdahl T. R. , Rustad A. B. , Theting T. G. , Stensen J. Å. , Øren P. E. , Bakke S. , Boassen T. , Palatnik B.
Published: December 2007

We discuss a two-step upscaling workflow to derive field-scale multi-phase flow parameters for depletion. The workflow was designed to increase the quality and reduce the uncertainty related to multi-phase aspects of advanced recovery methods in field-scale reservoir simulation. The upscaling workflow is applied to a realistic model, derived from an element model from the Statfjord field. In a previous paper we have demonstrated that steady-state upscaling yields valid results on the first upscaling step. In this paper, main focus is put on the second step, the transition from a fine-gridded geological model to a coarse-gridded simulation model. We show that in this case our steady-state upscaling tools are presently not able to accurately capture the effects of gravity. A dynamic upscaling (history match) was performed too, and gave a slightly better match. At present, the workflow has a relatively slow turnaround time, but this might be significantly improved by further development and automation of the different methods and tools that are involved. In essence, the upscaling workflow still needs to be improved.
Yard and Field Testing of a Tapered OD Coiled-Tubing System
Authors: Domann R. , Kalman M. , Sharma A. , Stephens R. K. , Chambers M. , Martin J. , McWhorter D. , Melancon J. T.
Published: December 2007

The concept of a tapered outside diameter coiled tubing system (TODCTS) was first presented in 2004.1 This paper laid out the basic requirements for a TODCT system and the advantages of the TODCTS in ultra-deep wells (30,000-ft range). The TODCT system includes: A modified injector that can handle more than one diameter of tubing and maintain a constant grip on the tubing throughout the length of the TODCT string.A "transition tube" that allows sections of tubing with different ODs to be joined together.Well-pressure control equipment (i.e., blowout preventer and stripper) that has the capability to grip and seal more than one diameter of tubing and can also grip and seal the transition tube.An operator control house that allows remote control of the stripper elements and injector gripper elements to open or close to different diameters of tubing while still maintaining control of well pressures inside the wellbore and grip on the tubing.

This paper continues the work that was started previously. A review of the yard testing completed on the equipment is included along with a subsequent field trial done onshore in south Texas. The end result is a tested and qualified TODCT system capable of safely running tubing strings into ultra-deep wells.
A Framework to Design and Optimize Surfactant-Enhanced Aquifer Remediation
Authors: Zhang J. , Delshad M. , Sepehrnoori K.
Published: December 2007

Surfactant enhanced aquifer remediation has become an acceptable remediation technology to remove groundwater contaminants such as petroleum hydrocarbons and chlorocarbons. There have been several recent field demonstrations of surfactant remediation where surfactants are used to significantly increase the solubility of the nonaqueous phase liquid (NAPLs) in water. The success of these tests was due to a unified approach using site characterization coupled with a laboratory screening followed by 3D modeling of the process for design and optimization purposes.

Here we present the design aspects of the subsurface surfactant flood with the emphasis on the flow and transport modeling. The University of Texas numerical model UTCHEM was used for this purpose. UTCHEM is a three-dimensional, multiphase, multicomponent chemical compositional simulator capable of modeling NAPL migration and groundwater flow and transport in aquifers. Simulations are performed to determine test design variables. These include wellfield configuration and rates, duration of injection and composition of surfactant solution, and hydraulic control achievement using hydraulic control wells.

We illustrate an approach to design and optimize surfactant-enhanced aquifer remediation processes in a systematic and efficient manner. To make the approach efficient, a framework that can distribute multiple numerical simulations on a cluster of processors has been successfully implemented. This framework integrates a chemical-enhanced numerical model, UTCHEM, an experimental design methodology, and a Monte Carlo algorithm with a robust global optimization search engine to identify the optimal combination under conditions of uncertainty.
Effect of Coiled Tubing Curvature on Friction Pressure Loss of Xanthan Foams
Authors: Gujar P. V. , Shah S. N. , Zhou Y.
Published: December 2007

This paper presents the results from series of experiments performed to study the effect of coiled tubing (CT) curvature on friction pressure loss of nitrogen gelled foam fluids. A Vi¬in., 10 ft of straight tubing and four sets of coiled tubing with curvature ratio (r/R) values of 0.01, 0.019, 0.031, and 0.075 are used in the experiment. A set of tests are performed using 20 and 30 lb/Mgal xanthan gum as base fluid and 0 to 80% quality nitrogen xanthan foams. Friction pressure data are gathered by monitoring the pressure drop across a 10-ft straight section and a given CT simultaneously. All data are gathered at ambient conditions and at a system pressure of 1000 psi. It is found that the friction pressure losses of nitrogen gelled foams in CT are significantly higher than the straight tubing even at low Reynolds number. The extent of CT curvature determines the magnitude increase in friction pressure loss. Empirical correlations for the prediction of friction pressure loss of gelled foams in both the straight and coiled tubing are developed for laminar, transition and turbulent flow regime. These are based on the dimensionless quantities of Fanning friction factor and generalized Dean number.
Efficient Closed-loop Production Optimization Under Uncertainty
Authors: Sarma P. , Durlofsky L. J. , Aziz K.
Published: December 2007

This work discusses a closed-loop approach for efficient real-time production optimization that consists of three key elements – adjoint models for efficient parameter and control gradient calculation, polynomial chaos expansions for efficient uncertainty propagation, and Karhunen-Loeve (K-L) expansions and Bayesian inversion theory for efficient real-time model updating (history-matching). The control gradients provided by the adjoint solution are used by a gradient-based optimization algorithm to determine optimal control settings, while the parameter gradients are used for model updating. Polynomial chaos expansions provide optimal encapsulation of information contained in the input random fields and output random variables. This approach allows the forward model to be used as a black box but is much faster than standard Monte Carlo techniques. The K-L representation allows for the direct application of adjoint techniques for history matching while assuring that the two-point geostatistics of the reservoir description are maintained. The benefits and efficiency of the overall closed-loop approach are demonstrated through real-time optimizations of net present value (NPV) for synthetic reservoirs under waterflood subject to production constraints and uncertain reservoir description. The closed-loop procedure is shown to provide a substantial improvement in NPV over the base case, and the results are seen to be very close to those obtained when the reservoir description is known apriori.
Productivity of Frac Stimulations in the German Rotliegend: Theoretical Consideration and Practical Results
Authors: Koehler M.
Published: December 2007

The main production of German gas fields is from sandstones of Upper Rotliegend age (Permian period). The Upper Rotliegend is characterised by a sequence of sandstones, siltstones and shale beds. Most of the present gas fields produce from low permeability layers (mainly 0.1-20mD) in a high pressure and high temperature environment. Hydraulic fracture stimulation has been developed to a regular completion concept in the last 15 years. Fracture stimulations, if applicable, are planned in all new drilling projects as a standard procedure to enhance the productivity of a well.

Due to the nature of the Upper Rotliegend depositional environment, a vertical to horizontal permeability anisotropy of about 1/10 can occur within the sandstones. Hydraulic fracture stimulations, in comparison to perforations, have proven to (i) bridge vertical flow barriers within sandstone/ siltstone sequences as well as (ii) to improve the connectivity of the stimulated layers horizontally. The result is an overall permeability capacity increase, vertically as well as horizontally. In addition, the effective productivity index enhancement pre and post frac, the fold of increase (FOI), is usually higher than theoretically expected from hydraulic fracturing.

Based on an "effective wellbore radius concept" to calculate the inflow performances of a fractured well, sensitivity studies were carried out to investigate the stimulation treatment results under different reservoir conditions. The main parameters, which have an impact on the fold of increase, are discussed. Based on transient well test analysis, 20 fracture treatments are compared with a theoretical radial inflow model with respect to their expected and observed productivity enhancement.
Development, Verification, and Improvement of a Sediment Toxicity Test for Regulatory Compliance
Authors: Dorn P. B. , Rabke S. , Glickman A. , Louallen J. , Nguyen K. , MacGregor R. , Candler J. , Wong D. C. L. , Hood C. , Hall J. , Purcell T.
Published: December 2007

The offshore oil and gas industry has moved toward the use of synthetic-based drilling fluids (SBF), changing potential exposure scenarios for discharged cuttings when compared to those of water-based drilling fluids (WBF). Unlike WBF, SBF sorbs predominately to particles in the cuttings and are not dispersed extensively into the water column, therefore, a sediment toxicity test was required by the US Environmental Protection Agency (US EPA) in addition to the existing water column test to define a best available technology (BAT) limit. Inclusion of a sediment toxicity test for NPDES compliance was precedent setting and unique. In order to fulfill the US EPA requirements, an inter-industry research group worked with EPA to develop a suitable test that met the technology-based discharge standard. Toxicity of discharged field drilling fluid is compared to a reference SBF (C1618 internal olefin) and, for compliance, the ratio of the reference drilling fluid median lethal concentration (LC50) to the field mud LC50 must be ≤1.0. Prior to its use, there were concerns that false positive results could cause incorrectly identified non-compliance events, limiting the use of SBF technology. Consequently, initial application allowed the use of a variability (K) factor in determining the ratio. After initiation as a compliance test, research was continued to reduce test variability and minimize false positives. That research included: 1) analysis of NPDES compliance data (500+ tests), 2) two inter-laboratory testing programs, 3) analysis of reference fluid data from one commercial laboratory, and 4) refinements to test sediment type and animal health. The results of these efforts to date are reviewed in this paper and are used to identify potential improvements in the application of the test as a regulatory tool.
Alaska Regulatory Guidelines for Qualification of Multiphase Metering Systems for Well Testing
Authors: Williamson J. , Mehdizadeh P.
Published: December 2007

Alaskan operators are investigating multiphase meter (MPM) use in well testing and field production allocation. The Alaska Oil and Gas Conservation Commission (AOGCC) is requiring approval prior to use of multiphase meters for production allocation purposes. The AOGCC prepared guidelines(1) and an accompanying technical primer(2) to aid Alaskan operators in gaining approval of MPM use. This paper provides the background for the development of the AOGCC guidelines and the expected role these guidelines will play in the approval of novel multiphase metering technology for well testing.
Automating Continuous Steam Injection in the Diatomite Formation, Midway Sunset Field, California
Authors: Holtzclaw J. I. , Branson Aubrey G.
Published: December 2007

This paper shows a successful automated system to control both steam rate and pressure in the heavy oil diatomite formations in the Midway Sunset field. Diatomite reservoir permeability is usually less than 10 md with naturally occurring fractures that promote premature steam breakthrough. In addition, this location was extremely shallow with the chance of surface steam eruption. The new system optimizes steam injection while controlling rapid pressure rise which could cause serious problems such as steam channeling and eruption out of zone.
Hydrate Monitoring and Warning System: A New Approach for Reducing Gas Hydrate Risks
Authors: Zain Z. M. , Yang J. , Tohidi B. , Cripps A. , Hunt A.
Published: December 2007

The current industry practice for hydrate prevention is injecting hydrate inhibitors at the upstream end of pipelines based on the calculated/measured hydrate phase boundary, water cut, worst pressure and temperature conditions, and the amount of inhibitor lost to non-aqueous phases. In general, systematic ways of controlling and monitoring along the pipeline and/or downstream to examine the degree of inhibition are very limited.

It is also known that hydrate formation would result in some changes in the aqueous phase. Therefore, it should be possible to detect initial hydrate formation by detecting these changes. The focus of our work is to develop a warning system against initial hydrate formation either by detecting minute hydrate particles and/or any changes in the water structure. The aim is to give the operator adequate time to initiate remedial steps prior to massive hydrate formation/build up which could result in pipeline blockage.

In this paper, we present a new approach for hydrate monitoring and warning system using physical property measurements such as dielectric properties and ultrasonic wave signal. The results demonstrate that dielectric properties at microwave frequencies has potential to be used as a downstream analysis and online analysis for detecting the initial hydrate formation and/or presence of hydrate particles and/or change in water structure due to hydrate formation. The ultrasonic signals (e.g., FFT and amplitude) could detect the presence of minute hydrate crystals and even nuclei, while there is no sign of hydrate formation from monitoring system pressure. The results are very encouraging and could potentially change the industrial approach to gas hydrate control strategy.

This work is part of a comprehensive project which covers monitoring the degree of inhibition against hydrate formation to further improve the safety of offshore/deepwater operations, as well as optimizing inhibitor injection rate to minimize their environmental impact and improve the economical aspects of the development. Some of the methods developed in this work are equally applicable to reducing the risks associated with wax and/or salt depositions, further improving the flow assurance aspects of deepwater developments.
Case History Evaluation of RPMs on Conform Fracturing Applications
Authors: Dos Santos J. A. C. M. , De Melo R. C. B. , Di Lullo G.
Published: December 2007

Actual worldwide oil production averages some 75 million barrels per day and, while estimates vary, this is associated with the production of 300 - 400 million barrels of water per day. These values of approximately 5 - 6 barrels of water for every barrel of oil are quite conservative. In some areas around the world, fields remain on production when the ratio is as high as 50 to 1.

Water production causes several problems to oil wells such as scaling, fines migration or sandface failure, corrosion of tubular, and kills wells by hydrostatic loading, amongst other things. Thus, while water production is an inevitable consequence of oil production, it is usually desirable to defer its onset, or its rise, for as long as possible.

Numerous strategies, both mechanical and chemical, have been employed over the years in attempts to achieve this. Simple shut-off techniques using cement, mechanical plugs and cross-linked gels have been widely used. Exotic materials such as DPR (disproportionate permeability reducers) and the new generation of relative permeability modifiers (RPM) have been applied in matrix treatments with varying degrees of success. Most recently, Conformance Fracturing operations have increased substantially in mature fields as the synergistic effect obtained by adding a RPM to a fracturing fluid have produced increased oil production with reduced water cut in one step, consequently eliminating the cost of additional water shut off treatment later on.

This paper is an evaluation of various RPM materials commonly used on Conformance Fracturing treatments performed in the northeast of Brazil and other South American countries, rather than the usual laboratory testing methods and theoretical estimations. The paper also describes the technical design and operational methodology to treat single zone to laminated reservoirs with different mobility ratios. We believe conformance fracture techniques could significantly impact the development strategies of many fields worldwide.
Multilateral/High-Pressure Jet Wash Tool System Successfully Employed in Multilateral Wells
Authors: Lesinszki A. , Stewart C. , Ortiz A. , Heap D. , Pipchuk D. , Zemlak K.
Published: December 2007

Multilateral wells provide optimal recovery of reservoir pay and can become more prolific with stimulation or cleanout treatments. Downhole tools exist that index and allow the coiled tubing string to find and enter additional legs; however, they function using flow rate modulation. Any additional tool component beneath the multilateral tool that requires high pressure will suffer in performance because of the indexing multilateral tool. This technical paper addresses the performance of a new system that allows the indexing tool to find the lateral and then effectively treat the reservoir through the stimulation tool at the end. The entire cycle can be repeated for all laterals in the wellbore.

The results of field tests using this multilateral jetting system were similar to what was seen in yard tests perform at test facilities in Rosharon TX. Field tests showed that operating parameters produced clear indications that the system was operating correctly. All legs were efficiently and effectively treated to improve well production. Additionally, this system reduced the number of trips into the well from three to one, resulting in a 50 % reduction of time at the client's well site.
Economics of GTL Plants
Authors: Al-Saadoon F. T.
Published: December 2007

A unique approach for assessing the economic viability of gas to liquid (GTL) plants is utilized. The capital expenditures ("CAPEX") are based on the production of one barrel of hydrocarbon liquid per day (BLPD) whereas the annual operating expenditures ("OPEX") are expressed as percentages of CAPEX. Both expenditures cover the range of costs envisioned by various venders/investigators. It is assumed the overall thermal efficiency of GTL plants is about 60% and the plant operates 330 days per annum. The capital expenditures utilized in this study are 20,000, 25,000, 30,000, 35,000, and 40,000 USD/BLPD. The annual operating expenditures utilized are 5%, 6%, and 7% of CAPEX. Thus, the range of operating expenditures utilized is 3.03 to 8.48 USD per barrel of liquid hydrocarbon produced.

Two measures of profitability are utilized in assessing the economic viability of GTL plants, namely, rate of return ("ROR") and undiscounted pay-out time ("POT"). Rates of return used in this study are 10%, 15%, and 20% whereas payout times used are 4, 5, 6, 7, and 8 years. Construction periods of 3 and 4 years are considered in the analysis. It is determined, for a 3-year construction period, that when crude oil prices are in the range of 10.27 USD/Bbl (for 20,000 USD/BLPD in CAPEX, 3.03 USD/Bbl in OPEX, and 10% for ROR) and 37.76 USD/Bbl (for 40,000 USD/BLPD in CAPEX, 8.48 USD/Bbl in OPEX and 20% for ROR), GTL plants are profitable. Likewise, it is concluded that when crude oil prices are in the range of 10.48 USD/Bbl (for 20,000 USD/BLPD in CAPEX, 3.03 USD/Bbl in OPEX, and 8 years for POT) and 38.32 USD/Bbl (for 40,000 USD/BLPD in CAPEX, 8.48 USD/Bbl in OPEX, and 4 years for POT), GTL plants are profitable. For a 4-year construction period, crude oil prices range between 10.64 and 40.87 USD/Bbl rather than 10.27 and 37.76 USD/Bbl, respectively. Crude oil prices as function of undiscounted pay-out times, however, remain unaffected by the change in the construction period. It should be noted that it is assumed the premium on GTL products offsets the cost of feed stock gas. A general survey of GTL processes is also included.
Quantifying Environmental Benefits of Improved Oil and Gas Exploration and Production Technology
Authors: Godec M. L. , Johnson N.
Published: December 2007

This paper summarizes work that documents the technological progress made by the oil and gas exploration and production (E&P) industry and the environmental benefits realized from this progress. The paper provides quantitative evidence of the improvements in environmental performance made by the E&P industry, examines industry and societal trends, and highlights some of the specific technological improvements contributing to this improved environmental performance. This paper examines and quantifies how specific technological advances in the areas of oil and gas exploration, drilling, well completion and stimulation, and production operations -- primarily focused on improved efficiency, lower costs, and increased recovery -- have resulted in reduced environmental impacts. The paper demonstrates how these technological advances are allowing greater access and better development economics in environmentally challenging settings. Finally, the paper offers some perspectives on the role of research and development to support continued technology improvements in the future.
Energy Policy and Conservation Act (EPCA) Inventory: Good Data and Sound Science to Address the Issue of Federal Lands Access
Authors: Eppink J. F. , Johnson R.
Published: December 2007

The EPCA Inventory represents a first-time compilation of disparate datasets to assess the issue of access to federal lands and resources. Comprehensive datasets for the inventory comprise federal lands status, leasing stipulations, and oil and gas resource data. This paper examines the EPCA Inventory methodology, geographic information systems (GIS) analysis, categorization, and strengths and weaknesses.
Minimizing Environmental Impact: Exploration and Production on an Urban University Campus
Authors: Grey J. E. , Spady D. W.
Published: December 2007

The Appalachian Basin is one of the oldest hydrocarbon producing regions of the United States. After over 100 years of drilling and production, the industry was very comfortable drilling behind hills, in isolated areas, and generally away from population. To demonstrate modern oil and gas exploration industry practices and the ability to operate responsibly in a challenging environment, a well was proposed on the football field of the University of Charleston. Located in the heart of the city, the well was within sight of the West Virginia State Capitol, on a mineral lease owned by the University. In order to accomplish this project, a successful well required a tenuous journey through geological identification, regulatory hurdles, resident opposition, logistical restrictions, location stability concerns, drilling surprises and reclamation procedures.

This paper will detail the planning and process that resulted in a successful drilling project in an environmentally sensitive location. In addition to being on the banks of a major waterway, within sight of a State Capitol, and adjacent to an office building, the real hurdle was cooperating with a neighborhood that was as close as 501 feet from the wellbore. The project drew a significant amount of local media attention, as each aspect of the operation was cross-examined in various public forums.

The project brought together an E&P company and six of its major vendor partners, each donating their products or services to a project that earned strong community support. Working under intense public scrutiny, each part of the drilling and completion process was pre-planned, including noise generation, dust control, spill response, and evacuation procedures. In fact, an observation tent was erected on-site for the purpose of public viewing, an action that proved to be very much accepted by the residents.

As a result, the local University has their own source of energy, but more importantly, the industry has a greatly enhanced reputation in the community of operating in a clean, efficient and professional manner. This paper will journal the steps of the process, effectively outlining a template for future projects in sensitive urban environments.
Treating Disease Prevention Like Safety: Educating Managers and Employees to Think of Anti-Malarial Medications as PPE (Personal Protective Equipment)
Authors: Shallenberger L. G. , Buford D. L.
Published: December 2007

Proposal

As oil and gas industry employees are located in sub-Sahara African countries and other areas where malaria is endemic, non-immune workers need to adopt multiple strategies to prevent contracting this potentially fatal disease. Awareness training, personal protection against mosquito bites and vector control measures are all important in reducing Anopheles mosquito bites.

In addition, the prevention of malaria in non-immune individuals relies heavily on the proper use of effective anti-malarial medications, i.e., chemoprophylactic agents. In spite of implementing a comprehensive Malaria Control Program (MCP) and contractually requiring its contractors to implement similarly effective programs for their employees, ExxonMobil affiliates and projects (ExxonMobil) continued to experience Falciparum malaria cases among contractors' non-immune employees assigned to ExxonMobil, including two fatalities.

A multidisciplinary team was formed to identify opportunities to enhance the effectiveness of the MCP. One of the team's key recommendations was to develop and implement a Malaria Chemoprophylaxis Compliance Program (MCCP) to address identified malaria chemoprophylaxis use shortcomings.

At the heart of the MCCP is the random, unannounced acquisition of urine specimens from non-immune individuals for laboratory verification of the presence of an effective anti-malaria medication. Novel laboratory analytical methods were developed and validated, and forensic-type chain of custody specimen handling procedures were adopted. Individuals producing non-conforming specimens are subjected to a confidential medical review process to determine their ongoing fitness-for-duty in malarial areas. The MCCP was implemented in Chad and Cameroon, then in Angola, Equatorial Guinea and Nigeria. As other countries with ExxonMobil employees and contractors working in upstream and downstream operations are added to the MCCP, it is becoming clear that malaria prevention should be treated like other safety initiatives.

Traditionally, employees are issued properly fitted respirators and hard hats to prevent injuries and diseases from hazardous exposures. To be effective, employees need to be educated in the proper use of these PPEs and self-motivated to use them. Likewise, managers must ensure that employees traveling to malarial areas are issued appropriate chemoprophylactic agents and educated in their proper use. Employees need to be motivated and willing to use the medications as prescribed for optimal program results.
Northern Sahara Aquifers Protection: Casing Corrosion Problems and Defining New Well Construction Performance Objectives—Case Study: Hassi Messaoud Oilfield in Algeria
Authors: Dhina O. , Aissat M. S. , Belkheir K.
Published: December 2007

Well construction reliability is always of great importance especially when it is about drilling in an arid region that contains strategic groundwater reserves. This is the case of Hassi Messaoud and satellite oilfields (HMDs) in Algeria where aquifers of the Northern Sahara System (NSAS) Spread out. Problems closely related to well construction such as casing corrosion, cementing lack and also those of post- abandonment are encountered by Sonatrach and partners there.

The main environmental concern becomes, then, how to ensure a reliable and highly safe well design and structure by improving drilling practices and introducing innovative architecture technologies aiming at significantly reducing aquifers contamination risks.

This paper describes how Sonatrach has been able to deal with such problems. Besides, it points out how risks are assessed according to an appropriate method that was fitted for purpose. On the other hand, field data are used to analyze the occurring phenomena and lessons learned from what is considered as the most tragic disaster related to well construction in Algeria - that occurred in Berkaoui satellite field in 1986 -are stressed.

Furthermore, the paper summarizes the steps and the approach taken along the way in stating new drilling performance objectives for HMDs to meet world-class standards and fulfil NSAS protection commitment.
Time-Lapse Production Logging and the Concept of Flowing Units
Authors: Cortez O. D. , Corbett P. W. M.
Published: December 2007

Permeability heterogeneity is a well known feature that is present in most if not all reservoirs. Initially when the reservoir is in hydrostatic equilibrium the differences in permeability within the same reservoir unit do not manifest. However as soon as production starts and a pressure drawdown is introduced to the system fluids will start moving towards the wellbore following the easiest paths within the rock. Therefore a system of "flowing units" develops with time allowing the zones with relative high permeability to produce faster than the relatively low permeability zones.

When a well is completed and perforated it is good practice to evaluate reservoir properties and well performance by carrying out transient well testing and multirate tests. Well test interpretation gives a good estimation of kh, skin and boundary effects. Multirate tests, particularly important in gas wells and high flowrate oil wells, allow evaluation of well deliverability and non-Darcy effects. It is therefore important to define the correct thickness that is actively contributing to flow. The effective thickness will be the sum of all the high permeability flowing units. In fact, and depending on the permeability contrast, the few most permeable units are responsible for most of production. Production Logging can verify and quantify flow contribution from these intervals.

Differential depletion within this interbedded layered system occurs by stages. Initially the zones with the highest permeabilities will produce faster and drain their connected volume until a differential pressure threshold is reached and crossflow from the surrounding poorer-quality reservoir facies starts. A production logging survey is a snapshot of the flowing profile across the producing intervals at that particular point in time. In order to monitor this dynamic behaviour running production logging surveys at different times during the field's life is highly recommended especially in mature fields that produce from layered systems or interbedded units within the same formation. Time-lapse production logging provides a realistic visualization of flowing behaviour and helps pre-development of a production optimisation strategy focused in maximizing reserve recovery.

The previous statements are supported by field examples where this pattern of permeability zonation has been observed over time.
Aluminum-Based HPWBM Successfully Replaces Oil-Based Mud To Drill Exploratory Wells in an Environmentally Sensitive Area
Authors: Ramirez M. A. , Clapper D. K. , Sanchez G. , Luna E. , Preciado O. , Santamaria J.
Published: December 2007

Oil-based muds traditionally have been used by Petrobras to drill wells in the Upper Magdalena Valley of Colombia to address wellbore instability problems associated with the Villeta shale. Recently the operator faced additional challenges while drilling an exploratory well due to 1) environmental concerns in a highly sensitive area, and 2) formation evaluation problems associated with oil-based fluids.

Significant advances in mud design in the last few years have allowed water-based mud performance to approach the performance of oil-based mud. Therefore, the operator and fluids company created a task force to evaluate the application of water-based mud for this well.The planning stage included laboratory tests, past history review and an evaluation of the service company's experiences when drilling similar shales in the area.A high performance water-based mud (HPWBM) containing clay and shale stabilizers, a ROP enhancer, and sealing agents was selected to drill the well.

This paper presents the laboratory and field data generated during this project. The well was drilled through the troublesome shale section and to the top of the production reservoir without experiencing wellbore stability problems. The system was resistant to carbon dioxide and anhydrite contamination.Gas kicks were controlled without difficulty and the fluid exhibited excellent rheological properties when higher densities were required to control formation pressures.The operator's expectations were met in this difficult well although areas for improvement were identified for future applications.These include enhanced resistance to anhydrite contamination, increased control of bit balling, reduced hole enlargement and improved ROP through hydraulics optimization.Additional testing to address these issues is planned using shale samples collected from the well. The operator and service company concluded that a properly designed water-based mud is a viable alternative to an oil-based mud in areas where environmental restrictions and formation evaluation problems are a concern.
Maximizing Portfolio Value with Specified Assurance
Authors: Holden C. W.
Published: December 2007

Maximizing value with limited capital while recognizing uncertainty balances cost, risk, and reward. The choices of objective function, risk measure, and constraints should be natural and free of bias and the methodology practical and adaptable. The formulation should provide insights into the portfolio and individual projects.
Cost-Effective Treatment of Barium from Coalbed Natural Gas Produced Water
Authors: Cline J. T.
Published: December 2007

Produced water is generated during the production of coal bed natural gas (CBNG) from the Big George coal at Anadarko Petroleum Company’s (APC) County Line field, near Gillette, Wyoming. The produced water contains dissolved solids that typically meet drinking water standards. But, the total barium limit of 1.8 mg/L, established by the Wyoming Department of Environmental Quality (WDEQ) for discharge to draws leading to the Powder River, was often exceeded for produced water discharging into multiple tire tanks, draws and ultimately into the Powder River. Originally, gypsum was used in the field to reduce the barium levels, but the monthly monitoring results were sporadic. This study was performed to (a) investigate reliable methods for reduction/removal of total barium from the discharge water, in order to meet the limit, and (b) design and construct cost effective treatment systems. The removal mechanisms tested were; (a) precipitation as an insoluble sulfate, or (b) adsorption on zeolite. Precipitation chemicals tested were: sulfuric acid, magnesium sulfate solution, and magnesium sulfate crystals. Even though soluble barium was decreased as a result of sulfate addition, the precipitation mechanisms were not successful in reliably reducing/removing total barium. However, total barium was dramatically and reliably removed by adsorption/filtration in direct, flow-through beds of zeolite, with flow rates of over 500 bbl/day/ton of zeolite. The designed zeolite beds (tinhorn tanks), at each outfall will maintain total barium in the discharge water below the established limit for four to eight weeks before renewal or burial as a non-hazardous waste.
Value Assessment Using the Modified Black-Scholes Equation
Authors: Rasmussen M. L. , Civan F.
Published: December 2007

The Black-Scholes equation is frequently used and critical for assessment of the value of investments and projects, such as dealing with petroleum reservoir exploration, development, and production, involving significantly high capital-intensive investment and prospect values. This paper presents a functional analysis of the Black-Scholes equation and develops analytical solutions under various conditions. It is demonstrated that the analytical solutions besides the special Black and Scholes’ solutions can be derived by means of the method of Laplace transformation. The generic analytic solutions and the analytical solutions for two specific boundary conditions are presented. The functional behaviors of these analytic solutions are demonstrated by parametric studies and applications. The solutions presented here are expected to be instrumental in understanding and application of these solutions in future studies. The analyses and analytical solutions presented can be readily extended for valuation of forward contracts and commodity options.