bluuebunny/crossref_metadata_2025 huggingface dataset:
Continuum Damage Theories and Petroleum Geomechanics
Authors: Cheng Harry H. , Dusseault Maurice B.
Published: December 2007

We present a new continuum damage mechanics constitutive model for brittle geomaterials based on irreversible thermodynamics with internal state variables. Damage is incorporated by a vector-valued internal state variable that can be interpreted as the local void density in a cross-section with normal n within a representative material volume element. The thermodynamic basis, free energy function, damage evolution equation, and damage-induced inelastic compliance are derived. It is shown that damage causes strain-softening and positive dilatancy, as well as decrease of the material stiffness. Comparisons of the model predictions with well-known experimental data on rocks and concrete under uniaxial and triaxial compression stresses are given. This model could be valuable in appropriate Petroleum Geomechanics cases.
Accidental Geomechanics - Capturing In-situ Stress from Mud Losses Encountered while Drilling
Authors: Edwards S. T. , Bratton T. R. , Standifird W. B.
Published: December 2007

The accurate determination of minimum horizontal stress magnitudes (Sh) can be critical to the economic success of oilfield operations from exploration through abandonment. Sh magnitudes are needed to optimally design drilling, completion and workover operations. While Sh magnitudes could be determined from a well-designed stress test, they are typically estimated from leak-off tests. These estimates are often inaccurate due to the different mechanisms affecting the leak-off pressure (LOP). These factors include among others the possible existence of natural or drilling induced fractures, the unknown stress concentration surrounding the wellbore, and the variability in test procedures used. These factors lead to significant differences between reported LOPs and Sh.

However, high quality stress measurements are often "accidentally" made while drilling. Most mud loss events characterized by wellbore ballooning, simulate an extended leak-off test, a high-quality stress test yielding an accurate value of Sh1. Wellbore ballooning is a term used to describe mud losses when the mud pumps are turned on followed by mud gains when the mud pumps are turned off. Wellbore ballooning is often caused by the opening and closing of fractures2,3. When circulating, the higher wellbore pressure opens and propagates the fractures and when circulation stops, the lower wellbore pressure closes the fracture returning mud to the wellbore. Fracture opening and closing pressures are better estimates of Sh, and can be quantified using downhole annular pressure while drilling measurements (APWD). Because circulation often starts and stops multiple times, multiple opening and closing pressures are recorded. The addition of time-lapse resistivity to locate the fractures completes this elegant and high quality stress measurement technique.

Examples are presented from 2 GOM wells where fractures in both sands and shales have been responsible for ballooning. Annular pressures measurements are then analyzed to determine Sh.
Application of Risk Analysis to Assessment of Casing Integrity and Subsidence in Deepwater Reservoirs
Authors: Abou-Sayed A. S. , Noble J. E. , Guo Q. , Meng F.
Published: December 2007

Various geomechanical-modeling approaches, which cover a wide range of techniques and complexity, have been developed to assess the stability of a borehole and/or the integrity of well casing. The ability to confidently use these models can be limited, however, because they generally do not allow the model user to consider the "real-world" variability of the input parameters defined in the models. Often, these geomechanical models do not adequately accommodate the innate variability of the rock properties (mechanical and petrophysical) of the target reservoirs. Consequently, this deterministic approach too often results in uncertainty about the "correct" value of a critical parameter to use and insecurity in the model results. Decisions based on these results can later, not surprisingly, be found to be incorrect. Model users attempting to overcome the limitations noted above have tried various techniques. Subjective estimation, arbitrary "minimums", grading techniques, and stepwise estimation have all been commonly used.

Recently, more powerful techniques such as Monte Carlo simulation and decision analysis have come into popular use. Over the past decade these two techniques have been extensively used in the petroleum industry to evaluate and solve a wide range of analytical problems in reservoir engineering and the geosciences. In this paper, the application of these techniques to a number of generalized geomechanical problems will be illustrated. A Monte Carlo simulation enables the user to identify, measure or estimate, and evaluate uncertainties in the problems being analyzed. The simulation models the random behavior of the input variables much like in a game of chance. That is, the variables have an uncertain value within a known range for any particular time or event. Numerical model and software packages are developed based on the Green's function for a nucleus of strain in the reservoir. The model is coupled with reservoir simulations to evaluate pressure maintenance and reservoir development schedule effect on casing integrity, fault stability via sensitivity studies. The geomechanics solutions would be coupled with both commercial or in-house developed reservoir simulators. The results of multiple simulations, done to determine the most likely outcome of various wellbore solution options, are reported in the current paper.
Characterization of Shales for Drilling Purposes
Authors: da Fontoura Sergio A. B. , Rabe Claudio , Lomba Rosana F. T.
Published: December 2007

This paper describes an integrated methodology to characterize shales from an engineering point of view. Shale samples from offshore Brazil were used throughout the study. The proposed methodology includes laboratory tests designed to characterize the rock individual constituents, i.e., solid particles and pore fluid, and to describe the rock microstructure. Complementary laboratory tests on the same materials indicated low potential of reactivity when in contact with saline solutions in spite of the presence of highly expansive clay minerals. The paper suggests that other elements besides simply the characteristics of the clay minerals should be considered when evaluating the potential of reactivity of shales.
Development of an Orthotropic 3D Elastoplastic Material Model for Shale
Authors: Crook Anthony J. L. , Yu Jian-Guo , Willson Stephen M.
Published: December 2007

Shales encountered in the overburden above hydrocarbon reservoirs often pose challenges to the stability of boreholes. Consequently, there is a keen interest in borehole stability prediction, which is complicated by the laminated structure of shale that arises as a consequence of the depositional environment.

A combined experimental/numerical investigation is being undertaken to address how the directional properties of shale impact borehole stability in weak shale formations. Within this paper an advanced finite element procedure for simulation of progressive damage of orthotropic pressure-sensitive materials is presented, which includes bifurcation and post-bifurcation analysis. This constitutive model is based on critical state theory and is specifically designed to represent the characteristic deformation of weak shale formations. It includes orthotropic elasticity and an orthotropic pressure-dependent yield surface that is curved in the p-q plane, and which intercepts the hydrostatic axis in both tension and compression. A regularization procedure is also presented that ensures mesh invariance and correctly reproduces the dependence of strength on the size of the test specimen.

Calibration of the model parameters is also discussed and the model is validated by comparison with the results of uniaxial and triaxial compression tests for Pierre I Shale performed at different bedding plane orientations.
Quantifying Value Creation from Intelligent Completion Technology Implementation
Authors: Sharma A. K. , Chorn L. G. , Han J. , Rajagopalan S.
Published: December 2007

Oil and gas development is fraught with technical uncertainty. As hard as we try, subsurface anomalies continue to surprise the most gifted petroleum engineers, and as a result, we seek technology that can help manage reservoir uncertainty. A classic success story is 3D seismic technology, which has proven to enhance our reservoir knowledge and reduce capital investment uncertainty. Intelligent Well Technology is much the same, in that it reduces the negative effects of reservoir uncertainty on expected future production and cash flow.

Intelligent Well technology can provide an operator continuous/permanent down-hole monitoring coupled with the ability to reconfigure the well completion upon demand (through remotely operated flow control) without additional investment in response to reservoir knowledge gained over time. This ability creates value through reduced well intervention costs, reduced operating costs (i.e. through reduced surface facility requirements), reduced capital expenditures through innovative Intelligent Well Field Development Programs, increased production through commingling and increased recovery through enhanced reservoir surveillance and management. Moreover, the combined capabilities of real-time monitoring and flow control allow an operator the flexibility to actively respond to unforeseen reservoir driven events (i.e. early gas/water breakthrough or coning), effectively reducing future cash flow uncertainty.

Traditional discounted cash flow (DCF) models do not adequately value the benefits of operational flexibility, and thus often underestimate the value of intelligent well technology (i.e. the benefits of real-time monitoring and control).1 Real Option analysis has been shown to effectively quantify this value in cases regarding portfolio analysis and corporate capital management.2

In this paper, we describe a method to apply Real Options theory to quantify the value of Intelligent Well applications, including the value of reducing project volatility and risk. We derive the mathematics to quantify Intelligent Well value for four specific case scenarios and outline the methodology to manage more complex cases. Finally, we describe how the mathematical model can be incorporated into a larger workflow process to assess entire asset portfolios for potential Intelligent Well applications.
An Investigation of the Economic Benefit of Inflow Control Devices on Horizontal Well Completions Using a Reservoir-Wellbore Coupled Model
Authors: Augustine Jody R.
Published: December 2007

A finite-difference, lumped-parameter based, reservoir-wellbore coupled model was developed to characterize the economic benefit of inflow control devices on horizontal well completions. Baker Oil Tools' inflow control device (ICD), the Equalizer™, has been tested and analyzed as a standalone entity. Several correlations have been developed to quantify the pressure drop characteristics of this ICD. To show the positive effects an ICD has on an asset, one must quantify, not only the flow performance of the ICD, but the time dependent depletion scenarios of the reservoir in question.

In this paper, the benefits of a unique inflow control device will be shown by analyzing reservoir depletion scenarios with and without inflow control. Without inflow control, a horizontal completion is at risk of early water breakthrough. With early water breakthrough, the water cut tends to escalate due to its lower viscosity compared to that of oil. As the water cut escalates, oil production drops significantly, often leading to shutdown of the well and reserves being left in the ground. This paper will show the benefits of using an ICD by describing the model development of a hypothetical, yet typical, field and the subsequent analysis that drives the completion design of the horizontal well.

The model includes the reservoir, water oil contact, near-wellbore characteristics, wellbore, sand control screen, ICDs, basepipe, and production tubing, capital expenditure input, and real time calculations of net present value of the reservoir. The use of inflow control devices increases the capital expenditure, but the increased cost is more than compensated for by the increased production efficiency.

The technology presented can be extrapolated and applied to the analysis of well completions consisting of different types of hardware. Future developments of this type of analysis will be described.

This work provides three additions to the technical knowledge base of the petroleum industry; 1) use of a lumped-parameter finite-difference based model to couple the wellbore completion to the reservoir, 2) proof of the positive effects of inflow control devices on producing hydrocarbons, and 3) further information on using the "economics of reservoir depletion" to drive horizontal completion designs.
Swelling Packer for Zonal Isolation in Open Hole Screen Completions
Authors: Freyer Rune , Huse Arve
Published: December 2007

Open hole screen completions are efficient in installation and reliable in use if designed properly. The major weakness of Open Hole screen completions have been lack of zonal isolation. An Open Hole Zonal Isolation packer has been developed and installed in 5 wells with up to 14 packers per well. No downtime, operational time or installation failures were experienced. The packer construction is based on the swelling properties of rubbers with crude oil.
New Relationship Between Oil Company and Service Company Rejuvenates a Mature North Sea Gas Field
Authors: McIninch Bruce , McIntyre Alistair , Gulrajani Sunil , Norris Mark
Published: December 2007

Many of the once prolific North Sea reservoirs have been reduced to mature assets, with a majority having reserves down to a fraction of their initial value. A significant number of isolated pockets of hydrocarbon bearing sands, however, remain available for production. The advantage of pursuing such bypassed assets is the availability of an existing infrastructure to support any incremental production. The biggest challenge when considering production enhancement initiatives is the marginal nature of the associated economics combined with project risk. In addition, marginal and mature assets seldom generate required engineering firepower to solve complex problems. Lack of investment results in decreased production and downward spiral that only can result in often-premature field abandonment.

This paper describes how Marathon identified a requirement for an alternative commercial arrangement and together with a selected service company, built an effective team that rejuvenated a dwindling gas asset. An interdisciplinary study was initially undertaken to quantify and manage economical risk associated with this project. Previous attempts at rejuvenating production were revisited to assess reasons for their ineffectiveness, or success. An alternative commercial model was then applied to help overcome the marginal nature of the economics. A data acquisition campaign was subsequently undertaken to determine the optimum intervention alternatives. Successful execution of the intervention activities has delivered a two-fold increase to total field production.

Several recently introduced technologies were employed during the course of the project. The project also spawned multiple field practices. Their conceptualization, field implementation and long-term effects on production are also described.

Contributions. This paper will present the application and results from several initiatives, including: Descriptions of an alternative commercial model, where the operator and service company mutually participate in the project risk, and its rewards.Implementation of the lift-log procedure, a single trip, combined, coiled tubing N2-lift and production logging operation.Utilization of scale-inhibitor impregnated proppant. This specialized proppant prevents loss of conductivity due to scale deposition within a fracture.Technical, commercial and operational best practices for use with mature field rehabilitation projects.
Imaging Gravel-Pack Quality: Application to Deviated and Horizontal Wells
Authors: Gulrajani Sunil N. , Pittman Dennis , Herve Xavier
Published: December 2007

Horizontal well gravel-packing operations are known to exhibit a higher rate of premature screenout. The suggested causes of such failure range from extreme reservoir conditions (e.g., low in-situ stresses), to suboptimal drilling practices (e.g., extensive washouts), or even to limitations of the gravel placement process (i.e., accelerated carrier fluid leakoff). Premature screenouts are postulated with theoretical studies or with laboratory experiments. These approaches rely on idealized assumptions and therefore fail to explain gravel placement behavior observed in field practice. Further, currently available gravel-pack logging tools can provide only borehole-averaged measurements. These are inadequate in horizontal wells where the gravel-pack quality may not be radially uniform. In horizontal wells, an azimuthal, or localized, gravel-pack measurement is necessary for a proper understanding of the gravel deposition over the reservoir section.

This paper describes the development and application of a new gravel-pack logging procedure. The associated logging tool is based on a radically different concept of fullbore gravel-pack imaging. It focuses on discrete sectors around the wellbore, providing the ability to azimuthally measure the gravel-pack quality. Further, its combinability with other production-logging sensors ensures that all parameters pertinent to gravel-pack evaluation can be obtained using a short, compact toolstring with minimal logging time.

The gravel-pack tool can also be operated in memory mode and deployed with certain downhole completion components (i.e., the washpipe) before gravel injection. These components are normally retrieved upon completion of the pumping operation, bringing the logging tool through the gravel pack and back to surface. One can therefore obtain a gravel-pack log concurrently with the gravel placement procedure. This "logging while completing" approach will provide an enhanced gravel-pack quality measurement at a fraction of the cost of conventional electric line logging operations.

Multiple field examples that illustrate the field application of this logging tool are provided. The paper also provides field evidence of the gravel placement failure mechanisms that have been previously postulated by theoretical studies.
A Laboratory Feasibility Study of Dilute Surfactant Injection for the Yibal Field, Oman
Authors: Babadagli T. , Al-Bemani A. , Boukadi F. , Al-Maamari R.
Published: December 2007

The Yibal field, the largest oil field in Oman, comprises 15 % of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of dilute surfactant in addition to the current waterflooding scheme.

The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning process. Nineteen samples were exposed to waterflooding succeeded by dilute surfactant injection. Eight samples were directly exposed to dilute surfactant injection. The reason behind this scheme is the fact that some parts of the reservoir under study were totally watered out, due to field waterflooding, and some parts are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were also carried out. This is with the intension of covering fractured zones, where recovery by capillary imbibition during injection is a possibility. The investigation considered testing of twelve different surfactants available in the market at different concentrations. Five of these surfactants were nonionic, two cationic, four anionic, and one mixture of anionic and non-ionic. The selection of the optimum concentration values for each surfactant was based on the measured IFT values at different concentrations.

The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1 % of OOIP (out of 19 experiments) whereas surfactant injection (modified waterflooding) yielded an average of 69.9 % of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding, however, was obtained and found to be varying between 0 and 7.4 % of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is, therefore, more effective and recommendable to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.
Comparative Economics Of Deep Drilling In Anadarko Basin
Authors: Rietman N.D. , Rumph K.D.
Published: December 2007

In the Anadarko Basin, well development costs increase exponentially with depth. Average porosities for both sandstone and carbonate reservoirs decrease with depth in a predictable manner. Normal pressure and temperature gradients and a general porosity-water saturation relationship can be used to establish gas in place for reservoir rock at various depths. Recoveries can be calculated using typical permeability versus porosity data.

A base case with 10 feet of net sandstone pay at a depth of 10,000 feet was used for comparative purposes. A 0.15 probability of this case yields an expected discounted cash flow rate of return of 15%. At depths of 15,000, 20,000 and 25,000 feet, sandstone pay thicknesses of 29, 89 and 297 feet are required to match the base case in terms of volume of gas in place per dollar spent. If recovery rates are considered, these thicknesses must be increased to 34, 128 and 670 feet respectively, to maintain a 15% rate of return. Similar relationships are indicated for carbonate reservoirs.

Introduction

The purpose of this paper was to compare economic for wells in the Anadarko Basin for depths varying from 10,000 to 25,000 feet. Because of the low incidence ooil occurrence below 10,000 feet, only gas wells were considered. For comparative purposes, economics for a base case gas well at a depth of 10,000 feet were run. Economics were then calculated for gas wells at depths of 15,000, 20,000 and 25,000 feet. The following data were used:constant gas price, gas gravity and operating expenseexisting Anadarko Basin data correlating porosity with depthnormal temperature and pressure gradientsgeneral variations in water saturation and permeability with porosity

Pay thicknesses were varied to maintain constant economics at depths of 10,000 to 25,000 feet. Economics were considered both from the standpoint of maintaining a constant cost per Mcf of gas in place and also a constant cost per discounted Mcf of gas recovered. For this paper, the term "discounted Mcf" refers to the gas volume which is derived from projecting production rates with a deliverability model projecting production rates with a deliverability model and discounting those predicted volumes of gas with 15% present value factors. This approach considers both recovery efficiency and the present value concept of money.

BASE CASE

For this case, the following data were used:10,000 ft depth10 ft sandstone pay400 acre drainage area0.65 gas gravity (no condensate)4340 psia original pressure207 degrees F reservoir temperature12% porosity27% water saturation0.5 md permeability-4 skin factor215 psia pipeline pressure$475,000 producing well cost (1/3 equipment;2/3 intangibles)$380,000 dry hole cost$2.07/Mcf gas price$20/day operating expense50% tax rate (federal income, production and ad valorem taxes)3/16 royalty20 year double declining balance depreciation
Horizontal Wells Pressure Build Up Analysis in Orinoco Heavy Oil Belt
Authors: Briceno M. , Summers L. E. , Quijada O. J.
Published: December 2007

The innovative application of horizontal drilling technology has made the Petrozuata development project in Venezuela a great success. Petrozuata is the first of four strategic associations implementing an integrated development in the Faja trend, which contains 1.36 trillion barrels of oil in place and is one of the world’s largest heavy oil accumulations. The joint venture of Petroleos de Venezuela, S.A. (PDVSA) and Conoco, Inc., drilled 101 single lateral and 140 multi-lateral horizontal wells in the Zuata Field from 1998 to 2001 as a means of delivering production rates of up to 3000 BOPD per well from reservoir sands of 8° to 10° API oil.

Well test interpretation and analysis techniques have been applied to both single and multi-lateral horizontal wells. This paper summarizes the methodology developed to analyze pressure build up (PBU) tests in the single lateral horizontal wells and recent experiences with the application of state of art PBU analysis techniques in the Zuata field wells.

Because of the geological complexity of the fluvial-deltaic reservoir sands and the peculiar transient pressure behavior, it was necessary to integrate analytical techniques that identified the various flow regimes with numerical analysis that further quantified the analytic interpretation. The integrated approach allowed for improvements in the conventional analytical interpretation and provided a basis of incorporating refinements in the reservoir description when combined with geological and petrophysical data and interpretation.
Automatic Determination of Well Placement Subject to Geostatistical and Economic Constraints
Authors: Norrena Karl P. , Deutsch Clayton V.
Published: December 2007

Optimal well placement is a complex problem that requires detailed models of the reservoir structure/geometry and the petrophysical properties such as facies, porosity, permeability, and fluid saturation. The reservoir development team attempts to integrate all of these aspects when devising a well plan for optimal reservoir exploitation. Ideally the well locations would be selected with the assistance of a flow simulator; however, this is impractical due to time and CPU requirements. This paper presents a technique for selecting optimal well locations for fine-tuning with a flow simulator. The technique constructs the well placement problem as an optimization problem to be solved with simulated annealing. The global objective function consists of multiple component objective functions. Each component represents a desirable feature or constraint in the problem. Optimality is defined as the best balance among the component objectives. The format of the technique is flexible and can incorporate 3-D geostatistical models of uncertainty and multiple constraints. The proposed method iteratively refines initial well locations and trajectories until the global objective is maximized. Several examples are shown. Optimal well placement in a steam assisted gravity drainage context is illustrated.
Modelling a Double Piston Pump
Authors: Becerra Oscar , Gamboa Jose , Kenyery Frank
Published: December 2007

The idea of using serial arrangements of sucker rod pumps to efficiently produce heavy oil wells with high gas to oil ratio has been analyzed in Venezuela since 1996. However, models to calculate the dimensions of the required plungers have not been presented in previous literature. An analytical model is presented in this work, based on the geometry of the pumps and the properties of the fluids to be handled. This model was validated using experimental data acquired in a reduced scale test bench, where machine oil and air were used as pumped fluids. A good performance of the dynamic model predicting dina-graphic card was observed. It was also found that the static model was useful for determining the application window of any arrangement. At the same time, a poor performance of the flow model through valves was observed due to the simplifications assumed on the model of the process.
Quantifying the Impact of Grid Size, Upscaling, and Streamline Simulation in the Risk Analysis Applied to Petroleum Field Development
Authors: Ligero Eliana L. , Maschio Célio , Schiozer Denis J.
Published: December 2007

Geological uncertainties usually have a strong impact on the decisions applied to petroleum field development. Methodologies to quantify the impact of uncertainties are still not well established due to the amount of variables that have to be considered. The complete analysis usually depends on geological, economic and technological uncertainties that have different degrees of impact in the recovery process and may affect the decision process in different levels depending on the problem, reservoir characteristics, recovery mechanism and stage of field development.

The objective of this paper is to evaluate the importance of the numerical simulation process in a risk analysis applied to a petroleum field development. The use of fast estimation of recovery factor can be used in the exploration risk analysis but, during appraisal and development phases, more reliable techniques must be used to predict the reservoir performance in order to quantify accurately the impact of uncertainties and evaluate risk.

One of the drawbacks of the use of numerical simulations can be the required computational effort. Therefore, this paper evaluates the impact of using different degrees of accuracy in the procedure, calculating risk with different options of grid size, number of attributes, levels of uncertainties and also comparing the results with streamline simulation which is used also for very fine models.

The proposed procedure is tested in the SPE 10th Comparative Solution and a comparison is presented for several different options. Finally some conclusions are taken based on accuracy, required computational effort, model scale, comparing also results from simulation through finite difference model and streamline.
New Well Design Using Expandable Screen Reduces Rig Time and Improves Deep Water Oil Production in Brazil
Authors: Rosa Fabio S. N. , Bianco Luis C. B. , Barata Paulo A.
Published: December 2007

The Marlim Sul Field, located in Campos Basin, southeast Brazil, is the one of the largest oil fields in the country. The water depth ranges from 1000 to 1900 meters and has been developed by horizontal wells with potential productivity up to 5000 m3/d. Due to the presence of unconsolidated sandstones, sand control is mandatory and open-hole gravel-pack has been used to avoid sand production. The regular casing program consist of a 30" conductor casing, a 13 3/8" surface casing, a 9 5/8" production casing and a 5 1/2 " base pipe screen gravel packed in the 8 1/2" horizontal section. The application of new technologies such as rotary steerable tool, expandable screens and synthetic oil base drilling and completion fluids allowed a new well design, eliminating one phase in the well. This new design used a 30" conductor casing, 10 ¾" production casing and a combination of conventional 7" liner and a 5 ½" expandable screens inside of the 8 1/2"well. The liner and the expandable screens are deployed in one trip. After screen expansion, a cementing job is performed through a stage collar in order to isolate the formation above the pay zone. Besides the overall cost reduction, an increment in well productivity is expected. Simulations showed that compared to 5 1/2" base pipe screen, the increased internal diameter achieved by the expandable screens, increases the PI and establishes a better production distribution along the horizontal section1. Therefore, a delay in the water production is expected.

This paper is focused in the criteria used for the new well design and the operational procedures used for well construction.
Zero Discharge System: An Innovative Drilling Rig Design to Protect the Environment in Lake Maracaibo
Authors: Suarez D. , Segovia G. J. , Valera R. E. , Nava L. A.
Published: December 2007

In 1999 the operator entered into a 10-yr contract with an oilfield services company to drill and work over wells in mature areas of Maracaibo Lake. In this alliance the operator will share risks and involve the services company in the operations performance through an incentive-penalty scheme with the objective of reducing operation times and costs, protecting the environment, maximizing reserves recovery and introducing technologies to achieve the desired goals.

The engineers pooled their knowledge and expertise to build multipurpose green rigs designed for well construction and work over on Lake Maracaibo environment. Likewise, each rig has a sophisticated treatment system to recycle wastewater into water suitable for industrial use. The document presents how this system can avoid pollution and the wastes are sent onshore to be taken to a zone designated for their final disposal or recycling and the sophisticated system that these rigs have to operate with zero discharge of any pollutants in Lake Maracaibo.
Methodology for Engineering Analysis for Deepwater Drilling in the North Atlantic with a Dynamically Positioned Drillship
Authors: Reyna Erick , Kuchner Keith
Published: December 2007

A number of engineering and operational considerations are addressed during the planning stage of a deepwater operation. Most Deepwater operations occur in benign environments such as the Gulf of Mexico and West Africa. The subject well was drilled in the United Kingdom on the Western edge of the North Atlantic in an area of potentially severe metocean conditions. This paper summarizes the comprehensive analysis that was performed for a deepwater drilling operation utilizing a dynamically positioned (DP) drillship in this area. This analysis more accurately defined the guidelines required to operate the rig safely under anticipated Northern Atlantic sea state conditions.
Planning Fit for Purpose Solutions with Roller Technology - the Value of Applied e-valuation
Authors: Fraser Scott D. , Rennie Mike , Mason Colin J.
Published: December 2007

Extended-reach drilling and completion operations are often at the limits of current technology. Roller tool technology has frequently been used to overcome onerous torque and drag challenges associated with drilling and completing high angle wells. These tools significantly reduce mechanical friction, and as described in this paper, enable completion operations to match the reach obtained by current drilling practices.

Significantly, roller tool technology is currently being used to drill and complete a series of 16 horizontal wells from a semi-submersible rig in the North Sea. A record 15,360ft high angle well with a horizontal reach of over 13,300ft and true vertical depth (TVD) of only 2,900ft has recently been drilled and completed. This well sets a new benchmark for shallow extended-reach wells in the industry.

The appropriate application of roller tool technology is instrumental to cost-effective drilling and completion of high departure wells now, and in the future. In order to further progress this technology and to ensure that it is used in the most appropriate way, demands that quality data be captured from each operation and interpreted in a consistent and correct manner.
Offline Subsea Wellhead MODU Operations Provide Significant Time Savings
Authors: Kenda William P. , Allen Timothy J. , Herbel Ryan R.
Published: December 2007

BP has combined existing technology with appropriate SIMOPS (Simultaneous Operations) planning to safely achieve significant cost reductions in deepwater field development by running several subsea wellhead components offline of drilling activities. This was achieved by utilizing conventional subsea wellhead tools that have been adapted for use in open water with the support of a subsea winch located in the moonpool on a mobile offshore drilling unit (MODU) and an ROV. The traditional method of deploying and installing the equipment using drill pipe requires that this work be done in the critical path of operations, using the rotary table. This takes more time because running drill pipe takes significantly longer than deploying wire rope off a winch.

Offline operations included deployment of wellhead corrosion caps, gasket seal prep protectors, and two different stack-up height measurement tools, installation of lockdown hangers, guidelineless re-entry assemblies (GRA), brushing the wellhead bore, and injecting corrosion inhibitor. The ROV system capability has been key in removing these operations from rig critical path by facilitating the operation, installation and retrieval of the tools.

BP's Holstein Drilling Team challenged itself to generate best in class performances by installing the lockdown hangers and GRAs, using offline subsea wellhead tools and ROV technology. This offline operational approach was successfully used on BP's Gulf of Mexico Horn Mountain project. The Holstein Team refined the concept and redesigned the tools from lessons learned, allowing the scope of the work to be increased to 16 wells. Removal of the operations from the critical path resulted in an estimated savings of 31 days of rig time for the project. These repetitive operations on multiple wells, in a field development scenario, resulted in significant cost reduction of $9.75 million, while meeting all safety expectations.
The First Underbalanced Multilateral Well Branches Drilled in Brazil, a Field Case History
Authors: Lage Antonio C. V. M. , Sotomayor Gabriel P. , Vargas Angela C. , da Silva Paulo R. C. , Lira Humberto L. , Filho Paulo Silva
Published: December 2007

The present work describes aspects related to planning and execution of six multilateral horizontal branches drilled underbalanced (UB) in Carmopolis field, which is located in Sergipe/Alagoas basin, in Brazil's Northeast Region. This field, discovered in 1963, is the country's largest onshore oil accumulation and has its production zones, which consist basically of sandstones and conglomerates, depleted at about 700 m deep (TVD).

As the targeted formations are consolidated, UB drilling did not bring any special concern in terms of wellbore collapse. In order to achieve the required bottomhole pressure nitrogen was mixed with a synthetic based mud (SBM) after flowing down through the annular space between the 9 5/8″ and 7″ casings and passing through a 1″ aperture in the 7″ casing. After that, the two-phase mixture went up through the annulus between the 7″ casing and the jointed pipe drill string. This concentric casing approach for injecting gas made possible the use of conventional MWD, but it brought some concerns, which are addressed and discussed, about the maintenance of the UB condition while operating.

The first multilateral well UB drilled in Brazil is an example of the combination of different technologies as multilateral level 2 well design, UB condition and medium radius directional system. In addition, it also involved four different parties where the operating company worked together with two service companies and a drilling contractor to build a team and achieve operational success.
Development of a System for Diagnostic-While-Drilling (DWD)
Authors: Finger J. T. , Mansure A. J. , Knudsen S. D. , Jacobson R. D.
Published: December 2007

This paper describes development of a prototype Diagnostic-While-Drilling (DWD) system that provides high-speed, realtime downhole data while drilling. The system has been demonstrated in both laboratory and field drilling. Project background, benefits, major technical challenges, and field test planning and results are described.
Telemetry Drill Pipe: Enabling Technology for the Downhole Internet
Authors: Jellison Michael J. , Hall David R. , Howard Darrell C. , Hall H. Tracy , Long Roy C. , Chandler R. Brett , Pixton David S.
Published: December 2007

Drill pipe capable of transmitting high-bandwidth data from downhole sensors and surface control signals back to those sensors has been developed and successfully tested. The system incorporates a high-speed data cable that runs the length of each joint and downhole tool. The cable terminates at induction coils that are installed in protecting grooves machined in the secondary torque shoulders of double-shoulder tool joints at each end of the pipe. The coils are recessed in ferrite troughs that focus the magnetic field. The system is virtually transparent to standard rig procedures and offers robust, reliable operation.

The paper provides background data on prior work relating to telemetry drill pipe and contrasts the results of these efforts with the new system. The new system has successfully demonstrated data transmission rates of up to 2,000,000 bits/sec. Current mud pulse telemetry is limited to 8 to 10 bits/sec. Electromagnetic technology provides data rates of up to 100 bits/sec, but suffers from hole depth and formation related electric impedance limitations.

Full realization of system benefits requires further development of additional drill stem components with highspeed telemetry capabilities including HWDP, collars, jars and top drive subs. A top drive sub that incorporates the telemetry design has been successfully manufactured and tested and is described in the paper. Development efforts relating to other drill stem components are also detailed. The system has been tested in a laboratory environment and in test wells. Results of these tests along with plans for field-testing in actual drilling environments are presented.

Telemetry drill pipe can improve well and field productivity by providing more complete, real-time logging information and reduce drilling time and costs and enhance well control by providing real-time downhole drilling data and early kick detection.
Integrated Drilling Dynamics System Closes the Model-Measure-Optimize Loop in Real Time
Authors: Chen David C-K , Smith Mark , LaPierre Scott
Published: December 2007

This paper presents a newly developed "intelligent" system designed to avoid resonance and to reduce vibrations. The system integrates real-time BHA dynamics software and realtime downhole vibration data to provide accurate modeling results and data analyses. Unlike conventional BHA dynamics software that is run for well planning or post-run analysis, this system uses real-time data (e.g., WOB, inclination, DLS) to produce real-time updates of critical rotary speeds. The updates are then displayed along with the rotary speed to show if the rotary speed is too close to one of the predicted critical rotary speeds. In addition, the modeling results can be compared with actual real-time downhole vibration data to corroborate the actual downhole condition. Field data have shown that the new system is effective in identifying the vibration mechanism and avoiding harmful vibrations.
Risks Assumed in Drilling Contracts: Global Comparison and Case Histories
Authors: Foster Stephen J. , Gibbie Karl W. , Mason Daniel C. , Baron Sheila L.
Published: December 2007

Drilling contracts are put to their test when a well blows out, workers are killed or injured, equipment is lost in the hole, third-party claims are made against the Contractor or Operator for injuries or damages, or other calamities occur. It is the liability and indemnity terms within these contracts that become a focal point when such mishaps take place. As the activities of Operating and Contracting Companies expand to all parts of the world, Risk Managers are assessing risks under many different drilling contract forms. Every drilling contract will specify, to varying degrees, the responsibility of the parties (Operator or Contractor) for costs and the liability of accidents or losses. The reasonable and acceptable allocation of risks assumed by the Operators or Contractors in a given contract is essential to managing risks successfully.

This paper details the similarities and differences in the contractual risk allocation features of a number of Daywork Drilling Contracts selected from the major drilling areas around the globe. Numerous global contracts will be analyzed in conjunction with actual drilling case histories to illustrate the application of the language and terms under differing contract risk allocations. This information can provide a tool to assist in contract negotiations for assessing the risks and identifying which risk each party is willing or not willing to bear.
The Chad Project Drilling Start-Up… High Performance Expectations in a Remote Area
Authors: Roberts C. M. , Breeding D. L.
Published: December 2007

Between March 2001 and November 2002, drilling operations for the Chad development underwent start-up. Three purpose-built drilling and two completion rigs were delivered from Houston to the field location, assembled, accepted and put into service. Over 3000 tons of materials and supplies were shipped from worldwide fabrication and assembly yards; this material crossed oceans to the west coast of Africa and traveled more than 1000 kilometers by rail and/or truck through two countries to arrive in time for startup. An 850 person camp and more than 150 thousand square feet of warehouse and service space were constructed and occupied. A team of 2250 people was assembled; more than seventy percent of the team is made up of residents of Chad hired during and just prior to the start-up.

This paper provides an overview of the drilling aspects of the project behind the start-up, describes the socioeconomic framework within which the teams were assembled, and discusses the approaches and experiences of the team members as they made the efforts necessary to achieve the start-up in the remote country of Chad.
Optimizing the Cement Sheath Design in HPHT Shearwater Field
Authors: Ravi K. , Bosma M. , Hunter L.
Published: December 2007

The need for a fit-for-purpose cement sheath was recently emphasized in the HPHT Shearwater Field when annular pressures were observed on all but one of the production wells, either immediately or during the completion phase. Such annular pressures may result in an inability to produce the reservoir, which fully erodes the value of the asset.

The main objective of a primary cement job is to prevent formation fluids from migrating into the annulus so that the reservoir can be produced safely and economically. To achieve this objective, as a first step, cement slurry should effectively displace the drilling fluid in the annulus. The set cement sheath should then withstand the stresses induced by the well events and maintain integrity during the life of the well.

For the Shearwater Field, a rigorous design method was used to evaluate the integrity of the cement sheath as a function of its properties and formation characteristics. The design procedure was based on finite element modeling and simulated the sequence of events starting from the drilling phase, including cement hydration, well completion, and production.

This paper discusses ways to improve cement designs in the Shearwater Field. The methodology developed was used to optimize the design of future Shearwater wells, resulting in the specification of improved cement systems/methods. The criteria used to evaluate the cement sheath performance are discussed, as well as the effects of well events on cement systems for reducing the risk of damage.

The specification from this analysis was implemented in the field, and the optimized cement sheath withstood the stresses from well completions and other events. The new well is on production and all indications are that no annular pressure problems exist. Therefore, this design process can help improve the economics of constructing and producing oil and gas wells, resulting in a cost-effective life-cycle design.

The process can also reduce health, safety, and environmental (HSE) risks because it minimizes the potential for zonal isolation failures.