bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design and Performance Evaluation of an Ultradeepwater Subsea Blowout Preventor Control System Using Shape Memory Alloy Actuators
Authors: Ma Ning , Hu Ziping , Samuel Robello , Ehlig-Economides Christine A. , Song Gangbing 
Published: December 2007

Abstract
As drilling moves to ultradeepwater, conventional blowout preventers (BOP) actuation technologies based on full or partial hydraulics are unable to meet the API standard for control system response times because of long hydraulic fluid communication path between an offshore platform and a BOP stack on the sea floor. Now that an ultradeepwater subsea blowout preventer (SSBOP) control system using shape memory alloy actuators has been demonstrated in the laboratory, several practical issues can be addressed.
The experimental device uses nitinol smart alloy material (SMA). It can be actuated by electrical heating, thereby replacing hydraulic actuation and hydraulic lines with electric cables. Alternatively, the SMA actuator system can be activated by chemical heating. With significantly fewer components, the SMA system will dramatically reduce total cost and will increase operation reliability. The new device can easily be retrofitted to existing conventional subsea control system thus enabling other methods to be used as a backup. Most importantly, the innovative all-electric BOP will provide a much faster response than its hydraulic counterpart and will improve safety for subsea drilling. The BOP actuator uses strands of SMA wires to achieve large force and large displacement in a remarkably small space. Experimental results demonstrate that the BOP can be activated and fully closed in less than 15 seconds.
This paper considers chemical and thermal energy sources as alternatives to electricity and ways to trigger an automatic mechanism. Additionally, a model is used to calculate the SMA length and diameter that will be required to provide sufficient force for different types and diameters of BOP rams (blind, pipe, or shear) or the annular BOP, and the energy requirements in each case. The model also addresses the range of pressures and temperatures that can be handled. Simple guidelines are presented along with practical field examples for different types of BOP hook ups.
Optimized Perforation—From Black Art to Engineering Software Tool
Authors: Bell M. R. G. , Davies J. B. , Simonian S. 
Published: December 2007

Abstract
While assisting production engineers in managing the perforating process, Shell recognized the need for an engineering software tool to guide and advise them. It needed to address selecting the optimum perforating system for given well and formation properties, and work at log resolution to eliminate problems experienced with existing packages that use input values averaged across the reservoir.
After consultation with staff engineers, the tool was created in Excel to test functionality and later transformed into a desktop application. It includes a perforating system database built from published API data. This is not ideal, since API Section I data are an unreliable predictor of performance into stressed rock, but this is the only published data allowing direct comparison between systems.
The tool calculates depth of fluid invasion, stress-corrected penetration, and crushed zone properties at log resolution. An inflow profile and IPR curves are then generated. The analysis can be repeated for multiple guns to compare relative performance; for example, to assess whether incremental production predicted for a superior system justifies additional expenditure.
The user can also test the sensitivity of inflow performance to perforating system performance and input assumptions. If system performance is critical, this may encourage laboratory tests under representative conditions to verify penetration and inflow.
Developing the tool highlighted fundamental shortcomings in the industry's understanding of perforation, such as: how the crushed zone is formed and removed; the role played by pressure dynamics; the sensitivity of penetration and tunnel quality to formation and system parameters; and, how jet perforators perform in targets other than sandstone. This lack of understanding has contributed to technology stagnation, sub-optimal well performance, poor decision making in the area of sandface completions, and undue belief in the value of allegedly performance-enhancing perforating services.
The work also brought into focus critical issues such as the industry's dependence on API Section I data - as a result of which we continue to be hoodwinked by ‘record breaking’ penetration performance into concrete targets – and the lack of performance metrics in poorly negotiated long - term perforating service contracts.
As a result, Shell has initiated research programs to build a better understanding of perforating phenomena - the results of which will feed back into the software, refining its capabilities and increasing the user's ability to design and simulate perforating operations-is driving the development of new performance benchmarks, and is rethinking the way perforating services are procured.
Fracture Face Skin Evolution during Cleanup
Authors: Gdanski R. , Fulton D. , Shen C. 
Published: December 2007

Abstract
There remains considerable debate on the impact of fracture face matrix damage on cleanup and productivity of gas wells. The impact of the Cinco-Ley fracture face skin factor has been studied extensively, but normally using single-phase flow examples. Two-phase flow examples are usually limited to the impact on long-term production. This paper uses a new two-phase flow simulator to demonstrate the impact of fracture face matrix damage on both fracture treatment cleanup and fracture face skin evolution during cleanup and subsequent production. The simulator was validated by comparison of calculated skins with pressure buildup simulations evaluated using a high-end, third-party, pressure transient analysis package.
The study has demonstrated that fracture face skin relative to gas flow can be calculated continually throughout a simulation of fracture treatment cleanup and production. It was found that at lower matrix permeabilities, and subsequent higher capillary pressure curves, the impact of water saturation in the damage zone becomes much more important. Specifically, the effective fracture face skin relative to gas can be several times higher than expected based on single-phase flow. Furthermore, the figures show that at lower matrix permeabilities, the time required to achieve a reasonable fracture face skin relative to gas flow can require considerable production time, on the order of several weeks, even for moderate damage factors. The results demonstrate that in tight gas reservoirs (~0.01 md and less) even a moderate amount of matrix damage in a fracture face can result in high fracture face skins and exceedingly long times for treatment cleanup. As such, it becomes very important to minimize fracture face matrix damage during tight gas fracturing treatments.
Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination
Authors: O'Keefe M. , Eriksen K. O. , Williams S. , Stensland D. , Vasques R. 
Published: December 2007

Abstract
A new generation of sampling technology is introduced which allows a Wireline Formation Tester to sample reservoir fluids in open-hole with levels of filtrate contamination that are below measurable limits, in many cases. Furthermore, the time required on station to cleanup before sampling is significantly reduced compared to conventional sampling methods.
Formation fluid sampling has always been adversely affected by mud filtrate contamination, which introduces errors into the laboratory analysis and requires analytical methods to back-calculate the measured properties to the uncontaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance, that replaces the need for sampling during Drill Stem Tests and provides accurate fluid information for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves.
The application of this new focused sampling technology is presented using four case studies from wells drilled on the Norwegian Continental Shelf. A wide range of formation fluids and permeabilities are examined, in both oil-based and water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate, and explores the different factors that affect performance of the focused sampling technique.
An important consequence of negligible contamination is the ability to accurately measure fluid properties in-situ. And reduced cleanup time allows for multiple zones to be scanned efficiently. Downhole Fluid Analysis (DFA) can thus be utilized to reveal reservoir architecture that is unable to be determined by traditional wireline logs.
An Integrated Wellbore Stability and Sand Production Prediction Study for a Multi-Field Gas Development
Authors: Wu B. , Mohamed Nulwhoffal Arselan , Tan C. P. , Sukahar Md Wakif , Hong Teh Yat , Viswanathan C. , Yee Hon Vai 
Published: December 2007

Abstract
This paper presents a geomechanical study on the potential of wellbore instability and sand production for a multi-field gas development in offshore Peninsular Malaysia. The objectives of the study were 1) to develop strategies to maintain mechanical and time-dependent stabilities of extended reach wells, and 2) to assess sand production risk in the development wells and eliminate unnecessary downhole sand control. The data required for the study include: 1) in-situ stresses, including magnitude and orientation, and formation pressure, 2) mechanical and petrophysical properties of the formations transected by the wellbore, and 3) properties of drilling fluid and its interaction with shale formations. The likelihood of wellbore instability and sand production for the development wells was assessed using in-house developed wellbore stability and sand production prediction tools.
Mud weight stability profiles showing the variation of lower and upper bound mud weights with depth were developed for typical vertical wells. Critical mud weight contour plots which show the variation of lower and upper bound mud weights with wellbore azimuth and deviation angle for preventing mechanical wellbore instability were developed for various formations. In addition, a drilling fluid design methodology that can be used for quick and reliable determination of the optimum mud design (weight, type and chemistry) was developed for the fields.
Critical drawdown and critical reservoir pressure profiles for assessing sand production potential in the fields were established. Sand production was found not to be a major problem in the early stage of production. However, depletion in reservoir pressure and water-cut can significantly increase sand production risk.
A Multi-Component Dual-Porosity Model for Gas Reservoir Flow with Adsorption Behaviour
Authors: Lu M. , Connell L. D. 
Published: December 2007

Abstract
This study presents a modified dual-porosity model for multispecies gas flow with adsorption behaviour, which is formulated from an exact formal solution of a linear multicomponent gas diffusion process within a porous matrix block. Therefore, the coupling effects of mutual-diffusion are included in the representation. This new respresentation, in its first order form, exhibits to be a simple algebraic expression that is of an equivalent computational efficiency in comparison with the traditional Warren and Root. Yet, the mutual-diffusion effect is not present in the latter one.
A numerical algorithm is also developed for this model when the full form of it, which is of an integral form with history-dependency, is incorporated into a set of multi-phase and multi-species flow equations. A numerical example with the proposed model for a two-phase and three gas-species flow is performed in light of a parametric study, demonstrating that multi-component gas species interactions have significant influences on the flow profile. For instance, even if the off-diagonal diffusion coefficients are smaller by one order of magnitude in comparison to their diagonal counterparts, the resultant effect on model predictions can still be 10∼35%. Ignoring the diffusional interactions between the gas species, as is done with the Warren-Root, will introduce considerable deviations.
Methods for Real-Time and High-Resolution Formation Evaluation and Formation Testing of Thinly Bedded Reservoirs in Exploration Wells
Authors: Claverie M. , Aboel-Abbas S. , Mutiara C. S. , Harfoushian H. , Hansen S. , Leech R. 
Published: December 2007

Abstract
Thinly bedded reservoirs are increasingly a target of offshore exploration in the Malay Basin. These reservoirs exhibit heterolithic interbedding with vertical heterogeneity and a wide range of layer flow properties. This paper describes methods of real-time and high-resolution formation evaluation and formation testing used to characterize such reservoirs.
The formation evaluation of thinly bedded reservoirs has several objectives:
identify the layers that may contain hydrocarbons verify productivity and fluid types with formation testing and sampling calculate net pay thickness and uncertainty range.
The evaluation is complex because of bed geometry and lithology. The reservoir beds are often thinner than the resolution of the formation evaluation logs. They exhibit a silty lithology and fine grain texture, and require high quality borehole resistivity images to characterize their geometry. The exploration well offers the best chance to evaluate the prospect, but operational and economical constraints do not permit to core or test every potential reservoir. Therefore, a real-time evaluation must identify with certainty the prospects to test.
The sequence of real-time formation evaluation described here consists of the following steps.
Wellsite petrophysical analysis of: porosity volumes of clay, minerals and fluids permeability based on the combination of GR spectroscopy elemental yields, nuclear and sonic porosity, and array resistivity logs. Identification of thin beds, and computation of sand-count from an electrical borehole resistivity imager. Validation of the wellsite petrophysical analysis and the borehole image within two hours of recording the logs, and design of the wireline testing and sampling program.
A modular wireline formation tester is used to measure accurate in-situ pressures in potential reservoir rock and to establish fluid gradients and identify contacts. Additionally, local formation permeability is estimated from analyses of pretests, and is used to verify the productivity of thin beds identified by formation evaluation techniques.
A Case Study on the Numerical Simulation of Enhanced Coalbed Methane Recovery
Authors: Wei X. R. , Wang G. X. , Massarotto P. , Golding S. D. 
Published: December 2007

Abstract
A hypothetical pilot-scale project was studied to investigate the capabilities of existing coalbed methane (CBM) models in simulating the multicomponent gas sorption and diffusion in coalbeds for CO2-sequestration enhanced coalbed methane (ECBM) production. Further, the effects of coal properties, e.g. cleat permeability, porosity, cleat spacing, sorption isotherms of CH4 and CO2, and initial reservoir conditions, on CO2 breakthrough and methane recovery were investigated as well. The calculated results suggested that the multicomponent sorption equilibria described using IAS/Langmuir isotherm and extended Langmuir isotherm are quite different. The gas diffusion rate can not be accurately modeled using Warren & Root equation based on dual-porosity model (pseudo-steady state approach), which is so far the most popular approach used in CBM models to describe gas diffusion process. This indicates that a rigorous multicomponent gas diffusion model should be incorporated in CBM models to improve numerical simulation and prediction of CBM/ECBM production.
An Intelligent Hydraulic Fracture Optimization Model: A New Tool to Stimulate Low Permeable Oil Reservoir
Authors: Rahman M. M. , Rahman M. K. 
Published: December 2007

AbstractThe increasing demand for hydraulic fracturing to stimulate low-permeable reservoirs has lead to the use of various fracture optimization techniques to find optimum values of controllable design parameters. In case of inappropriate values of these parameters, many unexpected complexities may arise during treatments that lead to high treatment cost and low productivity. While recognizing the role of incompatible fracturing fluids and inappropriate execution of treatments, the role of inappropriate treatment optimization is not well investigated. To avoid complexities, one needs to solve a constrained model to screen out potentially problematic designs with the aid of an intelligent optimization algorithm, in contrast to the widely-followed conventional approach of unconstrained parametric optimization. This paper presents an integrated constrained model for treatment optimization to maximize production. The Model has incorporated many design constraints based on hydraulic fracture mechanics and industry experience, and the global optimization scheme is driven by an intelligent moving object algorithm. The design constraints relate fracture geometry and its growth, surface operational parameters, non-dimensional fracture conductivity, proppant number and proppant fall rate in the fracture. Successful viscosity scheduling of the fracturing fluid is particularly influenced by power-law parameters and shear rate in the fracture, which can be controlled by fluid preparation and controlled injection. These parameters are included in the free design variables in optimization work for the first time. A combined objective function is formulated to maximize production while simultaneously minimizing the treatment cost, and trade-offs between these two conflicting design objectives have been investigated. While applied this model to a low permeable oil reservoir to demonstrate its merits, an optimum treatment designed by this model has offered an incremental production by 100% and a treatment cost saving by 20% of their initial cost. Sensitivity results of various parameters also indicate the implication of design other than optimum.
Two-Phase Relative Permeability Prediction: A Comparison of the Modified Brooks-Corey Methodology with a New Carman-Kozeny Based Flow Formulation
Authors: Behrenbruch P. , Goda H. M. 
Published: December 2007

Abstract
The prediction of relative permeability has been in the past and is currently a very active research area, with theoretical, experimental and empirical approaches under consideration. However, it is fair to say that the complexities of relative permeability have to date eluded researchers and practitioners alike, in that there is no universal formulation that is able to predict two-phase relative permeability for the wide range of rock and wettability characteristics observed. This paper presents a new, generalised formulation, one that is truly predictive, and compares the same with the industry standard - the modified Brooks-Corey (MBC) formulation.
The MBC formulation is perhaps the most widely used, practical method describing laboratory-derived relative permeability relationships in terms of simple power functions. The shortcomings of this formulation are that it has no real predictive capability and the relative contributions due to pore structure components as compared to variation in wettability cannot be resolved. The new two-phase flow formulation presented is based on a phenomenological approach related to the Carman-Kozeny equation, and is able to resolve the above mentioned shortcomings.
Included are several laboratory examples and the results of a comparison of the two formulations is presented. It is shown how the new formulation is able to predict "the curvature" of relative permeability curves when only the endpoints are known, duplicating observed behaviour from steady-state relative permeability experiments. Alternatively, if the endpoints can be derived, correlated or estimated with the use of more fundamental data, the entire prediction of relative permeability is possible.
In conclusion, the formulation presented is able to predict two-phase relative permeability under steady-state conditions, not just merely fit data. The second advantage of this method is that it is theoretically based and does not involve any fitting parameters but involves relatively simple analytical expressions.
Reducing Uncertainty Through Downhole Fluid Analysis: A Field Case Study
Authors: Muruais J. M. , Young A. A. 
Published: December 2007

Abstract
One of the challenges that operating companies face during any oil field development project is to deal with the uncertainty associated with the data acquired in the exploration and appraisal phases, which can be ultimately used to forecast reservoir behaviour, hydrocarbon recovery, and production. This particularly applies to marginal fields where uncertainties such as geology (static information) and reservoir drive mechanism (dynamic information) may impact significantly the estimation of reserves and result in the termination of the project during the appraisal phase.
The context of this case study is the appraisal phase in the development of two fields with heterogeneous, thin shaly sand sequences, where potential sand discontinuity exists. The fields are located in the Intra-Latrobe formations of the Gippsland Basin, offshore Australia. Accurate field description and reserves estimation was critical for the outcome of the full field development project. Logging-while-drilling logs, wireline logs and wireline formation tester pressure data, identified a number of potential hydraulically isolated hydrocarbon-bearing sands. During data acquisition, the degree of uncertainty associated with some of these intervals was perceived as significant for the estimation of oil in place and prediction of reservoir behaviour.
This uncertainty was addressed by a comprehensive wireline downhole fluid analysis (DFA) program consisting of multiple pumping stations over the reservoir intervals. The program conclusively identified multiple independent hydrocarbon-bearing sand intervals and assisted critical interpretation of the sand continuity particularly the semi-continuous distribution of fluid composition and gas-oil ratio versus depth. The DFA data was pre-processed in real time, enabling more accurate preliminary hydrocarbon volume estimation, as well as establishing with more confidence the perforating strategy over the main producing intervals.
For the first two wells of the field appraisal campaign, samples were recovered from all the hydrocarbon-bearing intervals and analyzed in the laboratory. The comparison between lab results and DFA provided a benchmark for optimizing the sampling programme with DFA for subsequent appraisal wells.