bluuebunny/crossref_metadata_2025_split huggingface dataset:
Under-Rig-Floor Open Hole Logging in the Gulf of Thailand: Engineering Design of the Oil Industry's First Simultaneous Open Hole Wireline Logging and Drilling Operation
Authors: Upchurch Eric R. , Graves Kyle S. 
Published: September 2008

Abstract
Chevron Thailand, on average, drills 12000′ MD / 8200′ TVD wells in about 4.5 days. The factor that most contributes to this level of performance is the "offlining" of as many drilling rig activities as possible. In our drilling operation almost all pipe handling and cementing operations are performed offline (i.e., off the critical operations path and therefore simultaneous to other activities on the rig). We have now taken the next logical step in performing offline operations. In May 2007, Chevron Thailand introduced the world's first simultaneous open hole wireline logging and drilling operation on Seadrill RT-7 (a tender-assist drilling rig), and presently is deploying the same system on additional tender-assist and jack-up rigs.
This paper describes the concept of offline open hole wireline logging and the engineering design of the components that make this new concept an operational reality. The paper also discusses the engineering required to integrate the unique offline open hole logging components with existing rig systems (for both tender-assist and jack-up rigs). This complex integration of newly designed components with existing rig systems is the path by which Chevron Thailand is setting a new performance standard in offshore drilling. The benefits of this new system have proven to be significant in improving Chevron Thailand's already world class drilling performance.
Development of a Coiled Tubing Specific Well Control Training Program
Authors: Egbert D. , Kendall H. 
Published: September 2008

Abstract
It is good safety practice to ensure that oilfield personnel on land and offshore locations become certified in well control. The certification is particularly important for drilling contractors and service companies doing certain types of work on a live well.
The International Association of Drilling Contractors (IADC) has developed standardized curriculums and an accreditation process for training programs providing certification in the area of well control. The conventional well control curriculum comprises some 36-40 hours of instruction on well control with heavy emphasis on equipment, procedures and techniques used in drilling.
Coiled tubing (CT) operations typically take place on a live well, and supervisors or other personnel involved in these operations are required to, or often seek certification in well control. However, it was determined that conventional drilling-oriented well control training may not provide adequate instruction on the specialized equipment, procedures and techniques (especially underbalanced operations) used in CT operations.
This paper will detail the three-year development of a unique IADC-accredited training program that certifies CT supervisors in CT-specific well control techniques. It will explain the safety reasons behind the decision to develop CT-specific training, with examples of how the training differs from conventional well control training, including the use of a realistic CT simulator.
Next-Generation Crosswell EM Imaging Tool
Authors: DePavia Luis , Zhang Ping , Alumbaugh David , Leveque Cyrille , Zhang Hong , Rosthal Richard 
Published: September 2008

Abstract
A new crosswell electromagnetic (EM) tool, now in field test, provides unique means to remotely sense the resistivity between two wells without having to drill an intermediate well. The wells can be open hole or cased with fiberglass, nonmagnetic chromium steel, or ordinary magnetic carbon steel.
This tool allows one to determine the resistivity distribution between wells spaced up to 1000 m apart. It is an induction measurement with a large magnetic field transmitter in one well and sensitive low-noise receivers in a second well. The transmitter generates a time varying field in the frequency range of 5 Hz to 1000 Hz. Since the transmitter and the receivers are not at a fixed position, the primary field cannot be cancelled as in conventional induction tools. Instead, the receiver senses the primary field of the transmitter combined with the secondary field produced by the formation between the wells. This secondary field increases with frequency of operation, formation conductivity and spacing between wells. In general, a high-frequency measurement with large formation effect is combined with a low-frequency effect to provide a geometry correction for the wells.
Data from multiple transmitter and receiver positions are processed through a two-dimensional non-linear inversion algorithm to produce a resistivity image of the formation between the wells. A priori information about the formation as well as conventional well logs are used to constrain or improve the image. Although the performance of this technique is strongly dependent upon the specific problem, the resulting image can be used for detecting bypassed oil, or in a time-lapse application, it can be used to monitor the movement of a reservoir or of injected fluid.
This paper presents the unique tool features, the survey planning process, and factors important for success as well as modeling and measurement examples. In addition, sensitivity to frequency and the starting model used as the initial step in processing the data to an image are examined.
Seeing the Forest as Well as the Trees: Creating Value with Portfolio Optimization
Authors: Reinsvold Chris , Johnson Eric , Menke Michael 
Published: September 2008

Abstract
"Can't see the forest for the trees" is an old adage that is bringing valuable new insight to oil and gas companies to-day. While portfolio management (PfM) in the oil and gas sector is not completely new, dramatic shifts in the industry over the past five years—marked by reduced availability of new resources, scarcity of technical personnel, and increasing interest in unconventional sources—is stoking interest in PfM at higher levels in many oil and gas organizations. Yet, PfM can require substantial effort and all too often has failed to deliver the expected decision making insight, perhaps because the analysis structure was too complex to yield strategic insights or it was not focused on actionable resource allocation choices.
This case study describes how the authors assisted a large oil and gas company we shall call Upland Oil in deploying a PfM process to develop insights and make decisions about resource allocation to long-term, high-stakes asset development projects. Financial, technical, and human resources constraints would not permit developing every asset in their portfolio at a maximum level; management needed to scale down development at some fields in order to accelerate it at others. With a thousand fields, and expertise dispersed among dozens of field managers, developing clear insights into portfolio strategy (discerning the forest as well as the trees) was challenging. Acceptance and buy-in from these technical leaders, as well as management, was necessary for success.
The authors helped Upland management meet these challenges by
Focusing the PfM effort on the major fields most likely to have significant improvement potential Articulating high, medium, and low investment alternatives for each of the 30 largest fields, and for the remainder of small fields Building a detailed simulation model of the production dynamics and economic consequences of these alternatives Adding a simplifying superstructure to this model that allowed efficient frontier-style optimization and sensitivity analysis
Upland's investment in the PfM process was rewarded. The analysis found that only one major field was being funded at an optimal level, while many warranted greater resources and many other development plans were over-resourced. Shareholder value added by implementing these recommendations is approximately USD 1 billion, about 10 percent of the total business value, with no increase in capital spending, a modest reduction in technical professionals required, and substantial reduction in rig requirements (which turned out to be a severe constraint in this case). Adding 10 percent to shareholder value is the financial equivalent of a major new oil discovery.
The Impact of Some Real Options on the Efficient Frontier of Portfolios of Oil Production Projects
Authors: Lima G. A. Costa , Suslick S. B. , Avansi G. D. 
Published: September 2008

Abstract
The efficient frontier of portfolios is an important tool for management because decision-makers can see how much return can be achieved using the total assets of the corporation and at the same time the level of risk. But, in order to create the efficient frontier, each project need to be analyzed previously – capital investment, production profile, capital cost etc. At the level of projects usually there are many real options available for management over the life of the project – drill additional wells, develop a satellite oil & gas field, oil production, make farm-out etc. When properly used, these real options have value and are an important tool for reducing the risk of NPV.
Then, a more realistic efficient frontier should consider the value of these real options, but in the practice of oil and gas business this does not always occur. In this paper, the study of the impact of some real options on the efficient frontier of portfolios intends to use an integrated methodology including real options, portfolio theory and Monte Carlo simulation. Three deep-water oil projects are combined in a portfolio, where the decisor has an option to sell the project if the payback period is not accomplished.
For the case of hypothetical situation, preliminary results indicated when there is availability of real options and management that can use them optimally, there are two main consequences: 1) the distribution of NPV is moved to the right and the efficient frontier is displaced towards more return and risk is reduced; 2) This way of thinking is important in order to a more effective policy for managing those variables that generate systematic risks (price, geology, etc). This model gives a better view of the true value of managerial flexibilities in the context not only of projects, but on the portfolio that is much more realistic.
Sub-Based Roller Tools Enable Effective Extended-Reach Completions Operations: Offshore West Africa
Authors: Long Tim Parker , McCormick John Edward 
Published: September 2008

Abstract
This paper describes the factors contributing to drag that required sub-based mechanical friction-reduction roller tools in an offshore extended-reach well (ERW). The information required for successful prediction of frictional forces and the preparatory torque and drag modeling are also covered. The paper describes how the tools were run and how they work. Finally, the paper presents the results in drag reduction and the effectiveness of the gravel-pack and perforating operations.
Applications related to this paper include any well with torque or drag challenges limiting the options for completion engineers, especially in extended-reach wells; and any drilling, fishing, or other operation restricted by torque or drag challenges.
Effective planning and running of specialized tools are required for success. In the subject well, drag was reduced sufficiently to take advantage of an otherwise unavailable well-completion method, resulting in increased production and earlier financial recovery of drilling and completion costs.
This paper helps familiarize the reader with the modeling techniques and information required to run torque and drag reduction tools and the axial drag benefits of roller tools that enable optimal completions in difficult or extended-reach wells. The paper also familiarizes the reader with the technology that the mechanical friction-reduction subs provide for drag reduction.
The Successful Application of a Compartmental Completion Technique Used to Isolate Multiple Hydraulic-Fracture Treatments in Horizontal Bakken Shale Wells in North Dakota
Authors: Mille Brent , Paneitz John , Mullen Mike , Meijs Raymund , Tunstall Mike , Garcia Mariano 
Published: September 2008

Abstract
Completing the Bakken shale in North Dakota presents options that are varied and complex. To achieve optimum recovery, the Bakken formation needs to be drilled horizontally and hydraulically fracture-stimulated. If the wellbore is drilled in the orientation to achieve a longitudinal fracture treatment, only one fracture treatment is needed and the issue of frac-stage isolation is not an issue. If the stress orientation is unknown, or the wellbore is drilled in the orientation for transverse oriented hydraulic fracture direction, then frac-stage isolation is an important decision. In the past few years, numerous methods have been tried to achieve good frac-stage isolation in the Bakken. A brief review of completion success in the Bakken identifies one method that has the highest degree of success when completing transverse-oriented hydraulic fractures. The best wells have an uncemented liner and a compartmental completion technique. These compartments can be tailored to cover specific areas of the borehole so the treatment is placed near the best shows. The frac compartments are created with the use of swellable external casing packers and ball-actuated stimulation sleeves. In one pumping event, multiple frac-stages are pumped, separated by opening individual stimulation sleeves selectively from the toe to the heel. The completion of two wells are discussed that show positive proof of this concept from a completion and production perspective.
Hydraulic Fracture Predictions with a Fully Coupled Geomechanical Reservoir Simulator
Authors: Dean R. H. , Schmidt J. H. 
Published: September 2008

Abstract
A new geomechanical reservoir simulator (GMRS®) has been developed which combines hydraulic fracture growth, multiphase/multi-component Darcy/non-Darcy porous flow, heat convection and conduction, solids deposition, and poroelastic/poroplastic deformation in a single application. The equations for the different mechanisms such as fracture width changes, laminar channel flow in the fracture, porous flow in the reservoir, heat convection and conduction, and poroelastic/poroplastic deformations are combined to produce an implicit fully-coupled formulation. The nonlinear system of equations is solved using a full Newton-Raphson expansion of all solution variables which enhances solution stability and allows second order convergence rates for the nonlinear iterations.
The program contains two separate criteria that one can use to model fracture propagation. Fracture growth computations can be based on critical stress intensity factors, or can use cohesive elements that exhibit strain-softening behavior. The critical stress intensity factor is based on the asymptotic stress/strain state at the tip of a fracture and is limited to linear poroelastic applications or applications where the plastic zone is small relative to the fracture length, while cohesive elements are based on energy release rates and cohesive stresses and can be used for both poroelastic and poroplastic applications. In addition to the fracture propagation logic, the program allows a dry zone to develop at the fracture tip as a natural part of the solution process. It is shown that a dry zone develops naturally at the tip of a propagating fracture for an example having a large pressure drop down the fracture.
The new geomechanical simulator is described and several examples are included to demonstrate the predictive capability of the application. Examples are also included to highlight the differences between the two fracture propagation models and to illustrate when a dry zone may be expected to develop at the fracture tip. The examples also allow one to compare the program's predictions with analytic solutions validating the fracture propagation algorithms used in the application.
Completion Design for Sandface Monitoring of Subsea Wells
Authors: Mackay S. , Lovell J. , Patel D. , Cens F. , Escanero S. 
Published: September 2008

Abstract
The expense of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity, drainage, and flow assurance. For those wells requiring sand control, an additional constraint is that sandface sensors must be deployed on a separate completion run. The objective of a recent engineering development program was to create a new deployment system that directly addressed these constraints. Instead of individual gauges on mandrels, digital sensors were miniaturized and distributed along a single spoolable bridle. In addition, a novel inductive coupling mechanism was developed to pass power and data from the upper to the lower completion. In a recent subsea deployment in the SouthEast Asia, such a coupler was attached to the top of a sensor bridle and both deployed as part of an openhole gravel-pack completion. Standard packers and gravel-pack service tools were used. The system became activated when a mating inductive coupler was landed as part of the upper completion. Surface indication of landing was provided by incorporating mechanical feedback into the lower assembly. With the coupler components in position, the tubing hanger was landed into the horizontal tree. Upon activation of the electrical penetrator, high-resolution temperature data were then immediately available across the length of the sandface, which was an industry first for a subsea producing well. No additional penetrations were required in the tree.
Development of this system required coordination from the operator because of the multiple vendors involved in the project. They supervised multiple qualification and system integration tests performed over the 2-yr development period to ensure ultimate success in the subsea deployment.
Field results showed that the mating inductive couplers provided high efficiency of power transmission so that industry standard power settings were sufficient to power a bridle with one sensor per joint of screen. The sandface data were available onshore during the cleanup phase, allowing the operator to monitor the cleanup in real time. Once the wells are brought online, the sandface data will further enhance the interpretation of flow allocation and reservoir drainage.
Sensor Architecture for Open Hole Gravel Pack Completions
Authors: Gambhir H. S. , Shrivastav A. , Lovell J. , Mackay S. , Chouzenoux C. , Juchereau B. , Arachman F. , Chaudhary A. 
Published: September 2008

Abstract
Measurements from permanent sandface sensors have been made in a dual-stage subsea well in the Bay of Bengal. Miniaturized temperature sensors were clamped to the exterior of sandscreens and transmitted their data across an inductive coupler back to the seabed by means of a downhole communication hub. The system has been permanently installed and was designed to provide interpretation data over the life of the reservoir. The completions hardware required to accomplish this was novel, but the implementation would not have been a success without attention to the overall instrumentation and controls architecture. Interface management was a key to the ontime deployment of the system.
The sensor data were transmitted in packed blocks that combined diagnostic information with raw temperature values. The communication hub merged those blocks with temperature and pressure values from above the production packer. Inductive coupling provided a wireless transmission of power and data between the upper and the lower completion. The combination was transferred to a subsea interface card in the tree which made the data available using a Modbus™ protocol. The Modbus data were transferred by subsea vendor protocols to a rack-mounted computer on the production platform. For the subsea vendor, there were essentially no differences between for sandface data versus for those wells with measurements only above the production packer. In particular, no additional or non-standard penetrations were required through the tree.
The sandface temperature data were transmitted in real-time during clean-up to the company headquarters in Mumbai, where they were staged onto an Oracle™ database. A thermal simulator has been configured to upload data from that database and provide an iterative inversion wherein reservoir properties are varied until simulated temperature data matches the measured data. Standard fluid modeling programs can then give a flow profile from those intepreted reservoir properties. The same thermal simulator will be used for production data, in which case the well data passes from the production platform to the same remote database using a redundant architecture.
Parametric Study to Enhance Oil Recovery Rate From Fractured Oil-Wet Carbonate Reservoirs
Authors: Gupta R. , Adibhatla B. , Mohanty K. K. 
Published: September 2008

Abstract
Waterflooding is not very effective in highly fractured oil-wet carbonate reservoirs. One of the ways to recover oil from such reservoirs is to use surface active agents to alter the wettability of the rock and recover oil through counter-current imbibiton or gravity drainage. Dilute anionic surfactant solutions (&lt;0.1 wt %) have been identified to recover 40-70 % OOIP recovery in laboratory scale. One of the limitations is that these processes are relatively slow. This paper discusses the parameters that can improve the oil recovery rates from the oil-wet fractured carbonates. Five parameters are discussed in this work which are found to increase oil recovery rates: extent of wettability alteration, interfacial tension (IFT), temperature, fracture density in the reservoir and pressurizing.
Systematic Prediction Errors in O&G Project and Portfolio Selection
Authors: Begg S. H. , Bratvold R. B. 
Published: September 2008

Abstract
The normal rule for choosing between alternatives in a decision situation is to select the one with the maximum estimated value. Due to uncertainty in the estimates (prediction errors), the mere fact of choosing the maximum induces a systematic bias that guarantees that, over repeated decisions, less than the estimated expected value will be realized. Although some "proof-of-concept" instances of this behaviour (variously termed Post-decision Surprise, the Optimizer's Curse, Inevitable Disappointment) have been reported, it is not well-publicised in the O&G world and its importance/relevance in realistic O&G decision situations has not been thoroughly assessed.
This paper places the effect in a more-widely applicable theoretical context and reports a systematic study that explores its impact on typical O&G decisions, using NPV as the value measure. Three typical situations, with different characteristics, are identified for investigation: intra-project alternative selection, using a Max[NPV] decision criterion; project "go"/"no go" decisions, using an NPV &gt; 0 decision criterion; constrained portfolio selection, using a Max[NPV/I] criterion, subject to a budget limit. Sensitivity analysis of the magnitude of the effect is carried out in each case.
We conclude that, whilst the effect is real and its magnitude may be large in some situations, it was of order 2% and 10% respectively, for the project and portfolio cases we analyzed. Further, the real prediction error, defined as expected difference between the true values of the selected alternative and the genuinely best alternative, was about half the above values. Given the range of other sources of prediction errors, plus the fact that its impact may be reduced due to corrective decisions as a project is executed, it may not, in practice, be as significant as previously suggested.