bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Drill Cuttings Reinjection (CRI) Case History On A Subsea Template Utilizing Low Cost Natural Oil Based Mud
Authors: Reddoch J. , Taylor C. , Smith R. 
Published: December 2007

Abstract
This paper covers the drill cuttings reinjection engineering and operating techniques utilized by British Gas and Apollo Services, on the three year Tunisian Miskar project off the coast of Sfax, Tunisia. At the time of this writing, British Gas has completed the subsea template phase, including the drilling and cuttings injection on 9 wells. A platform was installed in the last quarter of 1994 and the second drilling phase of this project began in March of 1995. A total of 11 or more wells are planned over a 3 year period.
Environmental regulations prohibited the dumping of oil based mud in the sea. Thus, if British Gas wanted the high penetration rates and, limited hole problems achieved by utilizing low cost, natural oil based mud, then cuttings reinjection presented the cost effective alternative.
All waste, from 8 wells, has been successfully pumped down three of the annuli with great success. Insignificant downtime has been experienced due to the injection process, even at instantaneous penetration rates in excess of 200 meters per hour on 12 1/4 inch hole. The CRI contractor rigged up and operated, with one man per 12 hour tower, the cuttings transfer system, the cuttings grinding/slurrification system and the triplex pump cuttings injection system. Over 2000 meters of limestone/claystone was encountered in each well while drilling and injecting successfully, (in the frac mode), into an impermeable claystone formation.
Addressed in this paper are: Well Planning with information on template drilling as it relates to cuttings reinjection.Injection well disposal design and planning, including multiple well casing points, for development drilling while producing.Requirements for surface equipment, personnel and commissioning.Field Results and Data with adjustments for unplanned events.Economics of CRI and natural oil base verses synthetic (psuedo) oil mud.Conclusions and recommendations for future work.
SYNENERGI - Production Chemicals and Process Design
Authors: Kaasa Øyvind 
Published: December 2007

Abstract
More cost effective oil production is possible if process design engineers start treating use of production chemicals in a more systematic way when they design new production platforms. Typically it is not common to include the effect of foam breaker and emulsion breaker when sizing separators. Design criteria for separators like foaminess and size of water droplets have little value when sizing separators if it is used without evaluating the positiv effect of the production chemicals. Testing on some of Norsk Hydro’s offshore facilities have shown that water treatment plants are not able to operate according to design without using emulsion breaker and a polyelectrolyt at low water cuts. Testing also indicates that a small oil stream from an oil sump can "polute" the oil-water separation system in the main separators because of its high content of surface active materials.
Injection systems for production chemicals are often added to the process on a "just in case" basis. Considering the importance of chemicals such as emulsion breaker and a polyelectrolyte, which are both vital to the quality of the water effluent, the process engineer should ensure that these chemicals work at optimum conditions. Parameters like temperature, concentration of active chemical component, and retention time in the pipe upstream of a processing vessel are important.
At the same time the oil companies requires that "green chemicals", combined with use of less chemicals in the effluent, to be used as part of their environmental policy. Unfortunately "green chemicals" are often less effective that other chemicals, making it difficult to reduce the amount of chemicals going overboard. The answer to the problems is to integrate the use of chemicals in the process design in order to achieve a synenergi effect.
A New MWD Concept for Geological Positioning of Horizontal Wells
Authors: Nakken E. I. , Mjaaland S. , Solstad A. 
Published: December 2007

Abstract
A key requirement in extended reach and horizontal drilling is to maintain the borehole trajectory within the productive interval. This is important for maximizing hydrocarbon recovery particularly when drilling thin beds and complexly folded and faulted reservoirs. The task, however, is often frustrated by uncertainty attached to the reservoir geology. This paper presents the conceptual ideas of an acoustic reference system for geological positioning of deviated and horizontal boreholes performed while drilling. The primary objective has been to extend the radial detection range from a few meters as of current geosteering tools up to at least 20 meters. By using acoustic reflection techniques, the borehole position is referenced to acoustic reflectors identifying critical stratigraphie bed boundaries or contacts. Theoretical analysis and experimental results, including cross well measurements with a full-scale prototype, demonstrate the feasibility of applying acoustic referencing for geosteering purposes.
The Use of CT Scanning in the Investigation of Acid Damage to Sandstone Core
Authors: Bartko K. M. , Newhouse D. P. , Andersen C. A. , Treinen R. J. 
Published: December 2007

Abstract
CT scanning1 has been used in acid flow studies in the past but has provided only qualitative information along the length of the core. A procedure for acid flow studies has been developed using a dual energy method on a CT scanner. This method determines the porosity change in volume elements in sequential axial slices along the length of the core. This paper describes the laboratory procedure used for the CT scanner to determine a treatment volume that is related to the volume of siderite in the formation.
Screenless Frac Pack Completions Utilizing Resin Coated Sand in the Gulf of Mexico
Authors: Kirby R. L. , Clement C. C. , Asbill S. W. , Ely J. W. 
Published: December 2007

Abstract
Removal of near wellbore damage and implementation of sand control through the use of Frac Packs with Gravel Pack screen in the hole is well documented in the Gulf of Mexico. However, an alternate procedure utilizing resin coated sand and conventional frac technology without Gravel Pack screens is now available. This paper describes the flexibility of such completions where multiple zones are encountered and the initial completions can be set up for future thru-tubing recompletions. In addition, the success of Frac Pack workovers on wells which were currently producing but rate restricted due to sand production is presented.
A discussion of well selection criteria, frac job design, gel systems, resin coated proppants, and field procedures is an integral part of the paper. Actual case histories are used to verify the success of the technique.
Frac Pack completions without screens in the hole are simpler and more versatile than those employing screens. Wells which encounter multiple small intervals which would not justify rig recompletions can be set up initially to facilitate future operations thru-tubing. By selecting the proper gel systems and resin coated proppants, formation damage removal, sand control, and stimulation can be realized without the use of screens. Field results back up screenless completions, recompletions, and workovers for small zones with less than thirty feet of perforated interval.
The Applicability of Current Slimhole Hydraulics Algorithms Under Field Conditions - A Critical Review
Authors: Thonhauser G. , Mülheim K. K. , Leoben Mining U. , Spoerker H. F. 
Published: December 2007

Abstract
Numerous publications have addressed the problems inherent to calculating well hydraulics in slimhole applications Accurate grasp of well hydraulics is of increased importance under slimhole conditions. Most models are valid in a controlled environment, but fail to fulfill the expectations under field conditions. Factors influencing the hydraulic behavior of the well have to be critically examined, and the accuracy of these factors entering into the calculations has to be quantified together with their relative impact on the results.
This work has compared several "established" approaches with field data from five deep slimhole wells, and critically reviewed limitations and possible advances in slimhole hydraulics’ calculations.
Analyzing field data showed phenomena that are not considered in existing simulations. This work tries to define these phenomena and evaluate their impact on future simulations. These factors influencing pressure loss and ECD development are listed and quantified, and examples from well data are presented.
A successful development of simulators of such complex systems is demanding a new way of thinking, away from the deterministic towards a probabilistic view of the problem.
Fiber/Proppant Mixtures Control Proppant Flowback in South Texas
Authors: Howard P. R. , King M. T. , Morris M. , Féraud J. -P. , Slusher G. , Lipari S. 
Published: December 2007

Abstract
Backproduction of proppant from hydraulic fractures (proppant flowback) is a continuing operational problem in the oil and gas industry. Up to 20% of the proppant can be flowed back after the treatment.1 Curable resin-coated proppants are used to control proppant production, but are known to chemically interact with fracturing fluids and may be prone to several failure mechanisms.2 Curable resin-coated proppants also require either well shut-in or the use of activators at low temperatures.
A new method to control proppant flowback relies on fibers mixed with the proppant to stabilize the proppant pack. The main advantage of this patented3 technology is that it is physical rather than chemical. Therefore, proppant flowback is controlled without specific shut-in time, temperature, or pressure constraints.
This paper presents flowback results from fractures of dry gas wells (&lt;l millidarcy permeability) where fí-ber/proppant mixtures were used to control proppant flow-back (11 cases). Fluid flowback rate, gas rate and proppant production were monitored during the cleanup period. These wells are compared to wells where either curable resin- coated proppants or no flowback control were used (15 cases).
The fiber/proppant mixtures controlled flowback of proppant for both sand and ceramic proppants when used with all the proppant or in only the last part of proppant (tail-in). Flowback could begin right after the fracturing equipment was rigged down (15 to 30 minutes). Cleanup fluid flow rates were up to ten times higher than previously obtainable with curable resin-coated proppants and less proppant was flowed back. Faster flowback rates also resulted in earlier onset of gas production and reduced flowback time. Fibers allow greater latitude in flowback rate than curable resincoated proppants without the need for shut-in time.
Plug Cementing: Horizontal to Vertical Conditions
Authors: Calvert David G. , Heathman James F. , Griffith James E. 
Published: December 2007

Abstract
This paper presents an in-depth study of cement plug placement that was conducted with large-scale models for the improvement of plug cementing practices and plug integrity. Common hole and workstring geometries were examined with various rheology and density ratios between the drilling fluid and cement. The critical conditions dictating the difference between success and failure for various wellbore angles and conditions were explored, and the mechanisms controlling slurry movement before and after placement are now better understood. An understanding of these mechanisms allows the engineer to better tailor a design to specific hole conditions.
Controversial concepts regarding plug-setting practices have been examined and resolved. The cumulative effects of density, rheology, and hole angle are major factors affecting plug success. While the Boycott effect and an extrusion effect were observed to be predominant in inclined wellbores, a spiraling or "roping" effect controls slurry movement in vertical wellbores. Ultimate success of a cement plug can be obtained if allowances are made for these effects in the job design, provided all other previously published recommended placement practices are followed.
Results of this work can be applied to many sidetracking and plug-to-abandon operations. Additionally, the understanding of the fluid movement (creep) mechanisms holds potential for use in primary and remedial cementing work, and in controlling the placement of noncementitious fluids in the wellbore.
Fracturing Pressures And Near-Well Fracture Geometry Of Arbitrarily Oriented And Horizontal Wells
Authors: Chen Z. , Economides M. J. 
Published: December 2007

Abstract
The hydraulic fracturing of arbitrarily oriented and horizontal wells is made challenging by the far more complicated near-well fracture geometry compared to that of conventional vertical wells. This geometry is important both for hydraulic fracture propagation and the subsequent post-treatment well performance. Fracture tortuosity of arbitrarily oriented and horizontal wells is likely to cause large initiation pressures and reduction in the fracture widths. This paper presents a comprehensive study of the effects of important variables, including the principal stresses, wellbore orientation, and perforation configuration on fracture geometry. Initiation pressures, the contact between arbitrarily oriented wells and the fracture plane, and the near-well fracture geometry are determined and discussed. This study also shows that because of the near-well stress concentration the fracture width at the wellbore is always smaller than the maximum fracture width. This can have important consequences during hydraulic fracturing.
New 2-MHz Multiarray Borehole-Compensated Resistivity Tool Developed for MWD in Slim Holes
Authors: Bonner S. D. , Tabanou J. R. , Wu P. T. , Seydoux J. P. , Moriarty K. A. , Seal B. K. , Kwok E. Y. , Kuchenbecker M. W. 
Published: December 2007

Abstract
To address the increasing number of slim holes being drilled in the range of 5.75 in. to 6.75 in., a mixed-borehole- compensated (MBHC) 2-MHz array resistivity tool with a 4.75-in. collar diameter is described for resistivity measurement-while-drilling (MWD) applications. MBHC is a unique technique developed to minimize the effects of borehole rugosity. The new MWD array resistivity tool makes multiple MBHC phase shift and attenuation resistivity measurements using five transmitter-to-receiver spacings. Five independent MBHC phase shift and attenuation measurements are made at 2 MHz. The five phase shift resistivities have similar vertical responses but with increasing radial depths of investigation. The five attenuation resistivities are also vertically similar but coarser and are radially deeper than the phase shift resistivities. This new array resistivity tool effectively exploits the technology and the interpretation methodology recently developed for wireline induction resistivities and the benefits of multispacing probes for formation evaluation. Most of the petrophysical applications developed in conjunction with the wireline resistivity AIT* Array Induction Imager Tool are illustrated from MWD array resistivity logs acquired while drilling.
Automatic Parameter Estimation From Well Test Data Using Artificial Neural Network
Authors: Athichanagorn Suwat , Home Roland N. 
Published: December 2007

Abstract
We propose a robust way of achieving a well test interpretation by combining the sequential predictive probability method with an artificial neural network approach. The sequential predictive probability method considers all possible reservoir models and determines which candidate model or models best predict the well response. This method is dependent on obtaining good initial estimates for the parameters governing the candidate reservoir models, which is achieved by applying the artificial neural network approach. We use the neural network to identify the characteristic components of the pressure derivative curve corresponding to the flow regimes known to be in each candidate model. Reservoir parameters are then computed using the data in the identified range of the corresponding behavior.
As a final step, the candidate models and their initial estimates are evaluated using the sequential probability method. The method discriminates between the candidate models and simultaneously performs nonlinear regression to compute the best estimates of reservoir parameters.
The trained neural network was able to identify the characteristic components of the derivative curve in most cases. The algorithm written to interpret the neural network signals into flow regimes required special procedures to take care of the misclassification from the neural network. The initial estimates of reservoir parameters from the neural network were found to be reasonably close to the eventual estimates from the sequential predictive probability method.
Integration of 3D Seismic Data in Reservoir Stochastic Simulations: A Case Study
Authors: Fournier F. 
Published: December 2007

Abstract
Integration of seismic data in stochastic models is a key point for reducing uncertainties on reservoir properties between wells. Stochastic simulations of the average porosity of a reservoir in North Sea, constrained both by well and seismic derived information, are discussed in this paper. Firstly, a non parametric regression based on a multivariate gaussian segmentation is used to calibrate at wells a set of seismic attributes in terms of average porosity. This technique allows to account for multivariate non linear relationships between seismic and porosity information, and also to fully quantify the uncertainties attached to the porosity estimation. Two approaches to account for the seismic derived information in simulations were compared. The first one is based on error cokriging where the seismic porosities constrain the simulations depending on their attached uncertainties. Seismic derived data significantly reduce the dispersions of the simulations, by comparison to the case where only well data participate. In the second approach, a cokriging between well and seismic porosities is used in the simulations. This allows to account for the spatial structure of seismic porosities and to better characterize well porosity spatial structure from its correlation with the dense seismic information. The non parametric regression appears as a way to linearize the seismic information before cokriging with well information.
Integrated 2-D Interpretation of Resistivity Logging Measurements by Inversion Methods
Authors: Eckard M. H. , Mezzatesta A. G. , Strack K. -M. 
Published: December 2007

Abstract
The determination of residual and movable hydrocarbons in oil and gas reservoirs requires that the formation resistivities are accurately estimated. For this purpose the log analyst can use several resistivity measurements with different measuring principles providing varying vertical and radial resolutions. Integrating these measurements into a uniform algorithm mat solves for the formation resistivities can improve the interpretation. Conventional interpretation methods of electromagnetic measurements use approximate and independent techniques for laterolog and induction logging measurements. These techniques do not necessarily provide the same results for the parameter estimates. Using a joint inversion algorithm that simultaneously solves for all measurements provides an earth model consistent with all measurements. In audition, the ability to resolve is enhanced due to the fact that galvanic and induction tools have different response characteristics in conductive or resistive formations. The laterolog is more sensitive to resistive formations; whereas, the induction tool is more sensitive to conductive formations. The combination of both measurements in a joint inversion process, therefore, increases the overall resolution. The inversion technique not only provides the formation parameter results, but gives the log analyst useful statistical information that can be used as quality control.
In contrast with the standard interpretations, which are normally based on a 1-D interpretation, the 2-D inversion can simultaneously solve for a resistivity distribution in the radial and vertical directions. When the resistivity contrast is high, the shoulder bed effects can be very strong. This can be the case if a reservoir is delineated by conductive shales. The different vertical resolutions between deep induction and focussed log measurements appear as an offset between the two curves which could be interpreted as invasion. The 2-D inversion is able to distinguish between shoulder bed and invasion effects and provides more reliable results than a standard 1-D interpretation. Shoulder bed effects may result in underestimating the amount of oil in place if the reservoir is embedded in a conductive formation. The problem of delineating the reservoir and determining the vertical boundaries of the reservoir (and subsequently its thickness, which can be used together with the resistivity to estimate the total amount of hydrocarbon) can be solved using a 2-D inversion.
This work demonstrates how the borehole, invasion and shoulder bed effects influence the data and subsequently the results of a standard interpretation. This is shown using synthetic and real field data.
Use of Pressure Transient Data to Estimate Permeability Variograms
Authors: Yadavalli S. K. , Jones J. R. , Krase L. D. , Yeh N-S. , Roadifer R. D. 
Published: December 2007

Abstract
Variograms for permeability are typically calculated using well log and core measurements, if they are calculated at all. Such procedures are inadequate to estimate variograms for horizontal permeability as they yield almost no information about the short lag structure of the variogram. A well test samples a much larger region of the reservoir than log and core measurements and thus, well test responses are potential sources of data for estimating the horizontal permeability variogram. In Ref. 1, we established the feasibility of calculating this variogram from a single set of well test data. Here we summarize further research on estimating horizontal permeability variograms from well test data. Our major focus in this paper is on improving horizontal variogram estimates by combining responses from tests on a number of different wells. We also address a few issues related to variogram estimation from single well test data. All work presented here is based on simulated well test data using permeability distributions generated with an imposed correlation structure and level of heterogeneity.
Use of Well Test Data in Stochastic Reservoir Modelling
Authors: Holden L. , Madsen R. , Skorstad A. , Jakobsen K. A. , Tjølsen C. B. , Vik S. 
Published: December 2007

Abstract
The aim of the study is to condition stochastic generated realizations on well test data in order to improve simulation of fades and petrophysics in fluvial reservoirs. First we have used the pressure data to estimate the shortest distance from the well to a possible channel boundary and thereby simulate the channel structures. The well test also provides the permeability average in the part of the channel intersected by the well. Together with core/log data and general knowledge of the reservoir this have been used to simulate permeability. These permeability realizations is input to a numerical flow simulator and compared with experimental results of the well test.