bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Porosity and Permeability on the Membrane Efficiency of Shales
Authors: Osuji Collins E. , Chenevert Martin E. , Sharma Mukul M.
Published: September 2008

This paper presents experimental data showing the dependence of shale membrane efficiency of water-base muds on its petrophysical properties and mud composition. Wellbore instability often occurs as a result of osmotic pressures that develop when shale is in contact with water-base muds. The osmotic pressures generated are proportional to the shale membrane efficiency. It is not currently possible to directly measure the shale membrane efficiency downhole. A pressure transmission technique was used to measure the membrane efficiency of Atoka shale at different porosities. This provides a way to estimate shale membrane efficiency from wireline measurements. The results of this study could possibly be used to design muds that cause shale strengthening and result in better wellbore stability.

Two series of tests were performed; the first used brine solution as the test fluid while the second used three industry-provided water-base muds. Results show that the membrane efficiency of Atoka shale ranges from 0.4% to about 13% and is a function of the shale porosity. This shows that the porosity of the shale itself is an important consideration in mud design. The data clearly show that the membrane efficiency is negatively correlated with the shale porosity until about a porosity of 7.5% beyond which there is essentially no change in membrane efficiency. A good correlation was also found between the shale permeability (which is in the order of 0.1 nD) and the membrane efficiency. Beyond a permeability of 0.2 nD osmotic effects are small.

For tests conducted with water-base muds, the membrane efficiency of the shale was reduced by a factor of more than 2 after contacting two of the three muds with the mud-altered Atoka shale. This decrease was found to correlate very well with an increase in porosity and permeability in the shale. However, muds which reduced the permeability recorded an increase in membrane efficiency. This shows the importance of porosity and permeability reducing agents in changing the membrane efficiency and osmotic pressure in shales.

Shale membrane efficiency has been shown to correlate with the shale porosity and permeability. Interaction of the shale with different water-base muds is shown to change the membrane properties of the shale. Furthermore, the nature of this change determines the effectiveness of these muds in the stabilization of troublesome shales. This is important because of the time dependent nature of wellbore failure. This study shows that certain drilling fluids have the ability to alter the shale through permeability reduction induced by osmotic flow. The results of the study can be used to better design water-base drilling fluids that will stabilize shales.
Characterization of Reservoir Heterogeneity through Fluid Movement Monitoring With Deep Electromagnetic and Pressure Measurements
Authors: Zhan Lang , Kuchuk Fikri , Ma S. Mark , Al-Shahri Ali M. , Ramakrishnan T. S. , Altundas Y. B. , Zeybek Murat , Manin Yves , Tartaras Efthimios , de Loubens Romain , Chugunov Nikita
Published: September 2008

Cores, open hole logs, formation testers, pressure transient tests, and production logs are usually used to assess reservoir heterogeneity. A common limitation of these techniques is that they do not provide two-dimensional spatial information of reservoir characteristics. For example, cores and logs have excellent vertical resolutions, but very small lateral radii of investigation, and the pressure transient tests have a large lateral radius of investigation, but very poor vertical resolution. Constructing an appropriate simulation model requires rescaling the data, and that may introduce significant uncertainties. To address these limitations, we explored the use of electrode resistivity array (ERA) measurements in a carbonate formation for reservoir characterization. The ERA was installed on tubing in a barefoot well rather than permanently cemented outside the casing as in previous applications. This notable difference introduced particular issues in the ERA data acquisition and interpretation, but also provided flexibility for device installation and operation. Furthermore, the ERA measurements were carried out in conjunction with low-salinity water injection and production in the same well. It was found that the ERA voltages near a source electrode showed unique characteristics that represented local formation heterogeneity. Although the new technology can be used at any scale, the focus was on characterizing formation heterogeneity within the length of the ERA string in the vertical direction and about 100 ft laterally around the wellbore. The scale of the investigated formation heterogeneity is comparable to grid sizes used in current reservoir simulations. Models were developed to identify stratified permeability heterogeneities from the time-lapse ERA voltages. The stratified heterogeneity estimated from the ERA measurements was compared to and verified by open hole logs and core analyses. The final heterogeneous reservoir model from ERA was subsequently applied to a numerical simulation that integrated the dynamic fluid flow, salt transport, and electrode array responses for water front monitoring and multiphase formation property evaluation and confirmed the first pass estimates of the identified heterogeneities.
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

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

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

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

"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

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

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

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

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

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

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

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 (<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

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 > 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.
Economics of Oil Shale Development in the United States
Authors: Biglarbigi Khosrow , Dammer Anton , Mohan Hitesh , Carolus Marshall
Published: September 2008

Oil Shale is one of the world's largest known fossil fuel resources. More than 1.8 trillion barrels of oil are trapped in shale in Federal lands in the western United States in the states of Colorado, Utah and Wyoming, of which 800 billion is considered recoverable. This amounts to three times the proven reserves of Saudi Arabia. During the past decade, a lot of attention has been given to the various extraction technologies to make oil shale economically feasible. Rising oil prices and improvements in technology have made the development of oil shale economically viable.

Detailed economic analysis has been conducted on the potential development of oil shale. This paper will describe the four representative production technologies being considered by companies for oil shale development. These include emerging in-situ processes as well as traditional mining with surface retorting technologies. The paper will provide details of various components of capital and operating costs for each of these technologies and the price at which each of these technologies will be economical. In addition to presenting an evaluation of the economic viability of an oil shale industry, this paper also describes the costs and benefits of such an industry to local, state, and Federal governments. Measures such as jobs created (for example: 2.5 million barrels of oil shale industry will require up to 300,000 direct and indirect jobs), GDP, and imports avoided will be described.
A Comprehensive Comparative Study on Analytical PI/IPR Correlations
Authors: Choi Suk Kyoon , Ouyang Liang-Biao , Huang Wann-Sheng (Bill)
Published: September 2008

Inflow performance is one of the significant components to quantify the reservoir's capability to produce hydrocarbon. There are two commonly-used quantities to represent reservoir inflow performance: productivity index (PI) and inflow performance relationship (IPR). Both relate fluid flow rate to pressure difference between bottomhole and reservoir. Much effort has been made on developing the PI or IPR solutions suitable for specific circumstances since Darcy proposed the simple and useful Darcy's law in 1856. As a consequence, various correlations for PI or IPR calculation have been proposed from simple analytical solutions to rigorous numerical formulations in the literature.

As horizontal or multilateral wells have been occupying an ever-increasing share of hydrocarbon production since the 1980s, more accurate PI or IPR estimation has been emerging as an important issue in the petroleum industry.11 The correlations become more and more complicated and rigorous in order to accurately describe inflow performance for complex well geometries. They can provide a better prediction or estimation of inflow performance, though they would be costly and computationally demanding. On the other side, researchers have been tried to simplify the complex solutions into analytical forms through extensive case studies. These provide a useful tool for the researchers and engineers to make quick estimations although they are confined to limited conditions.

In this paper, analytical correlations of PI and IPR from a comprehensive literature survey are reviewed. They have been categorized by well deviation, fluid phases and time dependence. The well deviation is divided into vertical (less than 15°), slanted (15 to 60°), highly-deviated/horizontal (60 to 90°), and multilateral wells; while fluid phases are categorized into single oil, single gas, and oil flow in two phases. For time dependence, steady state and pseudo-steady state have been considered, however the transient state has been excluded. In addition, case studies for the specific input parameters have been conducted to show the effective range, trends, and limitations of correlations as well as to provide the selection guideline for an appropriate estimation of inflow performance. All correlations of PI and IPR have been organized in the table for quick reference.
The Importance of Culture in Safe Work Environments
Authors: O'Connor J. , Woodrick T. , Schneeberger N. , Dettmann J. , Kuang J.
Published: September 2008

This study examined the joint influences of general organizational culture and process safety culture on employee perceptions of workplace safety. Statistical modeling was employed to analyze survey responses of employees at a Canadian energy provider. Results indicated that general organizational culture had both a direct and indirect effect on perceptions of workplace safety, and that process safety culture partially mediated the relationship between general organizational culture and perceptions of workplace safety. Findings also indicated that process safety culture is a more proximal predictor of perceptions of workplace safety than is general organizational culture. Lastly, management's action-oriented commitment to safety was found to be the strongest predictor of safety perceptions.
Prestack Seismic Inversion Tracks In Situ Combustion: 4D Seismic at the Balol Field, India
Authors: Sen Mrinal K. , Vedanti Nimisha
Published: September 2008

We present a case study of application of seismic inversion in monitoring the movement of thermal front in a heavy oil Field, Balol of Cambay basin, India using onshore time lapse seismic data. The land seismic data aquired over the Field was very noisy and the seimic difference sections were not informative. Thus the primary objective of this study was to make the time lapse 3D seismic data useful and comparable to the baseline data and to track the anomalies related to the combustion process. In this case direct amplitude differencing was not expected to work because of low repeatability of the monitor data sets with respect to the baseline data. The three sets of 3D data acquired during pre- (baseline) and post-combustion stages (monitor data) were different in frequency content, amplitude and spatial alignment; hence it was not possible to generate the difference sections. We therefore carried out pre-stack inversion of the 3D time lapse seismic data. The P-impedance volumes were obtained by simultaneous inversion of angle stacks generated from time migrated data sets corresponding to three production time steps. The inverted P-impedance volumes show spatial variations of some low impedance zones with production time, which can be related to fluid movements. The results from seismic inversion show great promise to monitor movement of thermal front if more well control is provided.
Matrix Acidizing of Carbonate Reservoirs Using Organic Acids and Mixture of HCl and Organic Acids
Authors: Chang F. F. , Nasr-El-Din H. A. , Lindvig T. , Qiu X. W.
Published: September 2008

Hydrochloric acid is the most commonly used acid for carbonate acidizing due to its low cost and high dissolving power. However, there are two major drawbacks associated with using concentrated HCl solutions in deep wells. The first is its high reaction rate with carbonate rocks, which limits acid penetration in the formation. The second is its corrosivity to well tubulars. Hence organic acids become viable material for matrix acidizing to alleviate these two problems. Though organic acids provide the benefit of retardation and low corrosivity, their low dissolving capacity may still limit the wormhole penetration leading to insufficient stimulation of the formation. Therefore, opportunity exists to mix HCl with an organic acid to achieve productivity enhancement by optimizing the wormhole penetration and profile.

Organic acids that are utilized in stimulating carbonate formations include formic, acetic, and more recently, citric and lactic. Selecting a suitable organic acid for a specific acidizing treatment is more difficult due to complex thermodynamic equilibrium and reaction kinetics. The reactions between organic acids and carbonate are less understood than those of HCl with carbonate rocks. Organic acid/carbonate systems are complicated because of the presence of CO2, organic ligands, and potential precipitation of the reaction products; the organic salts of calcium and magnesium. Therefore, more testing and modeling are needed to better understand these reactions.

This paper discusses the required information to properly design an organic acid or HCl plus organic acid treatment. In additional to reaction kinetics, data such as carbonate dissolving capacity at reservoir temperature and pressure, solubility of reaction products, and the effect of HCl to organic acid ratio are needed to better design field treatments. Recommendations are given on what and how laboratory evaluation should be carried out to obtain this information.
Profitability of Deepwater Petroleum Leases: Emipirical Evidence From the U.S. Gulf of Mexico Offshore Region
Authors: Iledare Omowumi O.
Published: September 2008

This paper describes and analyzes deepwater petroleum lease sales and development in the U.S. Gulf of Mexico region. Descriptive and Discounted Cash Flow (DCF) analysis of lease specific data suggest that the risk associated with deepwater lease development increases with water depth, and the return on investments rises significantly with water depth as well. Our empirical analysis shows that multiple bids tended to generate higher bonus per lease than single bids; independent firms paid more bonus per lease than integrated firms in the Gulf deep and less in the slope. Further, the difference in economic outcomes for leases won and developed by integrated firms and independent firms was more pronounced in the U.S. Gulf deep (water depths > 900 meters) than in the Gulf slope (water depth of 200-900 meters). We found no evidence that solo venture leases out performed joint venture leases in a significant way in the deep, despite the fact that the high bonus per lease received for solo bidders was significantly lower than joint venture bidders, on average. In the aggregate, the economic outcomes for lease acquisition and development in the Gulf deep were significantly higher than in the Gulf slope.
Modeling the Economic Impact of Individual and Corporate Risk Attitude
Authors: Welsh M. B. , Begg S. H.
Published: September 2008

Walls' work [1, 2], based around Expected Utility Theory [3], has highlighted the relationship between corporate risk tolerance and value; and others have commented on the loss of value resulting from companies behaving in a non-risk-neutral manner (i.e. not using expected value (EV) to make decisions) [4].

Prospect Theory [5], however, extends Utility Theory [3] to describe decisions individuals actually make under uncertainty. Key features include: diminishing utility of returns, resulting in risk aversion for gains and risk seeking for losses; use of "decision weights" rather than probabilities; and asymmetry between losses and gains, with people weighting losses more heavily. All three effects impact on a person's risk tolerance (i.e., how risk averse or risk seeking they are).

We present four studies highlighting the impact of Prospect Theory on decision value and, particularly, changes in decision value resulting from differences between individual and company risk tolerances. Study one shows losses resulting from risk aversion due to diminishing returns, discussing and comparing individual and corporate risk tolerances; the second highlights the impact of using decision weights; and the third the effect of loss/gain asymmetry. The fourth study is not directly based on Prospect Theory but rather shows the effect of the chance of ruin [6] on risk tolerance.

Results indicate that the Prospect Theory effects cause changes in risk tolerance resulting in lost value compared to risk neutral decisions and that this is strongest when the probability of success is low. Any difference between individual and corporate risk tolerances also impacts on value. The results of the fourth study, conversely, show why it can benefit an individual or (less often) a company to be risk averse, as this is demonstrated to reduce the chance of ruin and thus can increase EV in the long run.

Finally, we discuss the implications of these findings for corporate and individual decision makers, arguing that the corporate risk tolerances observed by Walls [1, 2] are, in fact, aggregated individual risk tolerances which should be compared to ideal corporate risk tolerances calculated using the chance of ruin for a company with a particular portfolio of investments.
Optimization for Operational Decision Support: The Rig Fleet Management Case
Authors: Irgens Morten , Guzman Ricardo Prieto , Stamatopoulos Jacqueline , Jackson Ken
Published: September 2008

Exploration and Production (E&P) operations are becoming increasingly challenging to do well. Drilling operations are a good example. Planning, scheduling and operating the rig fleet are important functions. You do not need many rigs before minimizing rig movements and costs while maximizing utilization is practically unmanageable using a manual approach.

Recent advances in optimization and artificial intelligence technologies make it possible to support operational decision making and promote decisions that are aligned with key performance goals. These technologies address complex, dynamic situations, and show the tangible value of operational decision-making in real time.

Saudi Aramco in collaboration with Actenum Corporation has developed a software application where the rig schedule is optimized against multiple objectives, disruptions to the schedule are quickly managed, the impact of scheduling decisions on key performance indicators is immediately displayed, and schedule optimization is supported by a user interface enabling direct schedule manipulation in response to changing needs. The application brings near real-time automation to a previously manual process, applies optimization technology to dynamic, mission-critical operations, and strongly increases Net Present Value (NPV).

The results show reduced planning time, reduced response time, reduction in scheduling errors, improved "what-if" abilities and decision-making. The experiments reported in this paper show reduction in transportation cost and increased NPV, providing insight into the trade-offs between time-to market and operational cost.
Minimizing Sanding Risk by Optimizing Well and Perforation Trajectory Using an Integrated Geomechanical and Passive Sand-Control Approach
Authors: Rahman Khalil , Khaksar Abbas , Kayes Toby
Published: September 2008

The source of sand production is the presence of disintegrated sand grains due to rock failure at the wellbore and/or perforation walls. Decision for appropriate sand control strategy requires engineering analysis to evaluate timing and severity of sanding over the life of field conditions. Optimizing well parameters such as well trajectory, perforation orientation, and level of drawdown using geomechanical principles can minimize and delay sand production.

This paper presents a geomechanical modeling approach that integrates production history with information from drilling data, well logs and rock mechanics tests. A gas field in South Asia with 11 wells and several years of production experience is used to demonstrate this approach. Core-calibrated rock strength log profiles are estimated throughout the reservoir depth for all existing wells. A rock failure criterion at the sand face is developed as a function of in-situ stresses, rock strength, well trajectory, perforation orientation, reservoir depletion and drawdown. Sanding evaluation results are calibrated and verified with production data and evidence of sanding in existing wells. Sand-free operating envelopes and sand evaluation logs are then generated for all existing wells and planned infill wells for life of field conditions. Sand prone zones and timing of sanding are established as a function of depletion and drawdown for each well using production forecasts for the rest of field life. For new infill wells, optimum well trajectories, selective perforation intervals and optimum perforation orientations are proposed to minimize and delay sand production. Re-completion and utilizing passive sand control methods including selective and orientated perforations are recommended for a number of existing wells.

This paper is expected to provide well engineers with guidelines to understand the principles and overall workflow involved in sand production prediction and minimization of sand production risk by optimizing well trajectory, perforation orientation and selective perforation strategy.
A Case Study of Hydraulically Fractured Eddy County, New Mexico, Horizontal Wolfcamp Producers
Authors: Metcalf Arthur S. , Coronado Juan , Fisher Kelvin , Kvasnicka Dave E. , Castello Joel S.
Published: September 2008

In order to improve production and subsequent well economics in the Wolfcamp formation in Eddy County, New Mexico, horizontal drilling has been employed for the last seven years. Current stimulation practices in these horizontal wells involve hydraulically fracturing with proppant in multiple stages. The effectiveness of the various fracturing treatments on production responses is of interest, because any optimization or changes that can reduce stimulation costs improves profit. In addition, with the current shortages in all mesh sizes of sands, anything which reduces the quantities needed to effectively stimulate wells is a plus.

Production from a localized group of horizontal Wolfcamp wells was examined to establish the impact scenario that proppant choice made on performance. It was found that decline rates were the same or better on wells fracture treated using a significantly lower volume of an Ultra-Lightweight proppant compared to those wells treated with regular sand. This reduction in proppant used also resulted in a savings ranging from 4% to 33% of the stimulation costs.