bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Fibre-Optic Distributed Temperature Measurements to Provide Real-Time Reservoir Surveillance Data on Wytch Farm Field Horizontal Extended-Reach Wells
Authors: Brown G. A. , Kennedy B. , Meling T. 
Published: December 2007

Abstract
BP-Amoco operated Wytch Farm has installed fibre optic distributed temperature systems on 2 of their recent ERD (extended reach drilling) wells in order to provide real time reservoir surveillance. This novel new approach to reservoir monitoring has provided important information about the well and reservoir performance. This type of zonal contribution and fluid data would normally be acquired by running production logs on the end of coiled tubing at infrequent intervals, however the dual completion on Wytch Farm’s M-12 well made conventional production logging impossible.
Distributed temperature data has been recorded over 2 years throughout well tests and shut-ins, as well as during normal periods of production. Data analysis is performed both visually, by correlating time related thermal events observed in the well with known reservoir and production anomalies, and theoretically by comparing recorded temperature data with that predicted by thermal profiles generated using nodal analysis fluid flow and heat transfer software*. Use of this software* allows estimates of production by zone to be compared to actual recorded temperature data, enabling a variety of production scenarios to be investigated and the most likely identified.
The installation of real time fibre optic distributed temperature monitoring on Wytch Farm field has enabled the asset to recognise flow behind casing and cross flow during shut-in in the M-12 well and water finger encroachment to be identified in the M-17 well. This data has provided important information about both the reservoir and well performance in real time, which would not usually have become available until later in the wells life.
Fluids for Drilling and Cementing Shallow Water Flows
Authors: Whitfill Donald L. , Heathman James , Faul R. R. , Vargo Richard F. 
Published: December 2007

Abstract
Industry experience has emphasized the necessity for quick detection and quick control of shallow water flows. Pressure While Drilling (PWD) instruments showing an increase in annular pressure when drilling riserless with seawater will indicate produced sand. Shallow, well-developed, clean, geo-pressured formations will produce very large quantities of brine during an uncontrolled drilling operation. Because of high fluid velocities and the unconsolidated nature of shallow formations, large volumes of produced sand — and subsequent borehole enlargement — should be expected.
There are options for successfully drilling shallow water flow zones. A common scenario is to drill riserless with sea-water using high viscosity sweeps while also having kill fluid ready. If a saltwater flow occurs, evaluate the risk and cost scenarios of continuing to drill under-balanced versus containing the flow with large volumes of weighted fluids. This paper reviews a number of approaches using specialty fluids for drilling, along with their case histories.
Hundreds of case histories have proven that foam cement is the preferred approach to cementing casing across shallow water flow zones. Benefits include but are not limited to (1) vastly-improved displacement efficiency; (2) flow-control owing to the fact that an expansive fluid is in place during the phase transition from a liquid slurry to a gel with strength sufficient to suppress water flows; (3) ease of on-location job modifications. However, specialized blends are often required so that the cement (foamed or non-foamed) will function as intended at the low temperatures encountered across these zones. Use of these blends can complicate material handling logistics, especially on rigs with limited bulk volume capacity. The paper discusses the benefits of an all-liquid additive approach that allows the use of any Class A or Class H neat cement that may be on a rig. The chemistry of the additive package produces a slurry with the same capacity to control shallow water flows as the specialty blends. Case histories of these systems will be discussed.
The paper also discusses a decision flow chart designed to help the engineer better plan for controlling water flows related to drilling through shallow water flow environments.
Extending the Option Pricing Theory for the Valuation of E&P Projects
Authors: Zettl M. 
Published: December 2007

Abstract
Many attempts have been made to use option pricing theory (OPT) for the valuation of investment projects and especially for E&P projects. In this paper the various approaches are compared to each other. The discrete method using two kinds of binomial trees to describe the pre-drilling and the production phase, respectively is considered the most promising way to model complex nested options that exist in E&P projects. This model, however, has two major disadvantages. First, the oil price can reach unrealistic values due to using a multiplicative binomial process to model the price process. Second the uncertainty of other input values, besides the oil price, is not considered. To overcome the problem of extreme oil prices a price band that confines the oil price process is used. The uncertainty of the input parameters is incorporated by combining OPT with Monte Carlo simulation. Furthermore, it is proposed in this paper which evaluation technique should be used in a certain phase of an E&P project.
Identifying Controls on Reservoir Behavior Using Designed Simulations
Authors: White Christopher D. , Willis Brian J. , Narayanan Keshav , Dutton Shirley P. 
Published: December 2007

Summary
Reservoir simulation is widely used to investigate the effects of geologic heterogeneity and engineering parameter variability on reservoir production behavior. Because many geologic and engineering factors interact to affect recovery behavior, an exhaustive examination of variations due to all possible parameter combinations is prohibitively expensive. The factors that most strongly influence production behavior must be identified to focus analyses and measurements. Experimental design varies multiple factors simultaneously and minimizes the number of simulations required to construct accurate response models. Response models can statistically test the relative importance of the factors examined in designed simulations.
In this paper, a method based on response surfaces, Monte Carlo simulation, and Bayes’ theorem (RSMCB) was used examine the effects of several types of geologic variability and different modeling methods. The method is demonstrated in an analysis of outcrop data from a heterolithic tide-influenced deltaic sandstone. The data set includes thousands of probe permeameter measurements, detailed bedding maps, shale diagrams, cement maps, facies maps, facies-specific rock properties, and variograms.
Because of the importance of geostatistical methods for reservoir model construction, designed simulations examined the effects of varying geostatistical parameters and compared geostatistical and quasideterministic models of geologic variability. Intrafacies variations have statistically significant effects at the bed scale, although shale resistance dominates these effects.
Improvements in reservoir model accuracy were quantified by computing the expected changes in factor uncertainties resulting from response measurements. Posterior distributions of geologic and geostatistical parameters were estimated from flow responses. Monte Carlo simulations with prior and posterior factor distributions quantify the uncertainty reduction caused by measurements. Uncertainty reduction can be compared to measurement cost, enabling better informed measurement decisions.
Model Errors Inherent in Conditioning a Stochastic Channel to Pressure Data
Authors: Zhang Fengjun , Reynolds A. C. , Oliver D. S. 
Published: December 2007

Abstract
This work discusses an automatic history matching procedure to efficiently condition a stochastic channel to well-test pressure data, plus well observations of the channel thickness and depth of the channel top. Our emphasis is on computational difficulties that are related to the nonlinearity of the objective function or arise from the definition of effective permeability on a reservoir simulation gridblock that is intersected by one or more channel boundaries. We show that upscaling gridblock permeabilities for gridblocks intersected by channel boundaries introduces modeling errors. This errors cause spurious local minima in the objective function that must be optimized to obtain a realization of the model. We suggest a procedure to reduce the occurrence of spurious local minimum. We show that an automatic history matching procedure can be used to define upscaled permeabilities. We show, however, that when permeability contrasts across fades boundaries are extreme, this upscaling process may be dominated by the difference in local trucation errors between the fine and coarse grid systems.
One important objective of this work is to provide computational insight for the general problem of conditioning a reservoir fades model to production data by automatic history matching.
A Relationship Between the Fractal Dimension and Scaling Groups of Unstable Miscible Displacements
Authors: Gharbi R. B. , Qasem F. , Peters E. J. 
Published: December 2007

Abstract
A detailed two-dimensional flow visualization study was performed to examine the dynamics of viscous fingering in miscible displacements. Detailed quantitative miscible displacement experiments using a microcomputer-based imaging workstation on a variety of oil recovery fluid systems were performed. The effect of two dimensionless scaling groups, namely gravity number and viscosity ratio, on the displacement behavior was investigated. Based on image analysis, the irregular fingering patterns of the flow visualization experiments were analyzed for fractal characteristics.
Results indicate that the areal sweep efficiency of unstable miscible displacement follows a fractal scaling law with a fractal dimension and proportionality constant related to the gravity number and the viscosity ratio. The study shows that the fractal dimension decreases with decreasing gravity number and increasing viscosity ratio. This relationship was mapped by an artificial neural network model, which can be used to estimate the fractal dimension and the proportionality constant of miscible displacements as functions of the two scaling groups. These results have potential application in the mathematical modeling of unstable EOR displacements and in the scaling of laboratory displacements to field conditions.
The Evolution of a High Near-Wellbore Pressure Loss Treatment Strategy for the Australian Cooper Basin
Authors: Roberts Geoffrey A , Chipperfield Simon T , Miller William K 
Published: December 2007

Abstract
An extensive hydraulic fracturing program has been ongoing in the Australian Cooper Basin since 1994. Close to 100 "vertical" wells have been treated during this period in a high temperature/pressure hard rock sandstone environment, with a placement success rate of around 90%. The remaining 10% have almost all experienced some degree of high Near-Wellbore Pressure Loss (NWBPL), ie. 600–1500 psi, with this near-well fracture complexity preventing the placement of treatments. Despite the focus and publicity on this subject in recent years, severe and consistent NWBPL problems in vertical wells are "rare". Exceptions to this are highly naturally fractured formations (coal seams) and/or poor perforation practices. While it is often difficult to determine the exact cause of NWBPL, an understanding of its’ potential causes, coupled with field trials and accumulated experience in the Cooper Basin, has been distilled to obtain a set of tools and procedures to minimise its’ impact on all but the most severe cases.
Summaries of the Cooper Basin field trials conducted over the past five years are presented. This paper also introduces a cost effective, NWBPL management strategy based on the results from these trials that has been successful in over half of the problem wells. This strategy is based on a three-phase approach. It requires the use of NWBPL mitigation, remediation and tolerance initiatives.
Finally this paper presents three case studies in which the NWBPL management strategy has been successfully employed.
Surface and Downhole Tiltmeter Mapping: An Effective Tool for Monitoring Downhole Drill Cuttings Disposal
Authors: Griffin L. G. , Wright C. A. , Davis E. J. , Wolhar S. L. , Moschovidis Z. A. 
Published: December 2007

Abstract
This paper documents the application and final results of using surface and downhole tilt mapping to monitor and evaluate downhole drill cuttings disposal at the Joint Industry Mounds Drill Cuttings Injection Field Experiment Project. Knowledge of the created hydraulic fractures was critical for determining the placement of "core-through" wells to evaluate the fracturing disposal mechanisms for both sandstone and shale intervals. Through "real-time" monitoring of the fracture it was possible to detect fracture height growth while the test was being performed and measure that the injected fluids stayed in the intended zone. Surface and downhole tiltmeter diagnostics have been widely used for mapping conventional propped and unpropped hydraulic fractures; however, this is the first application of the combination of surface and downhole tiltmeters to evaluate fracture geometry during drill cuttings disposal.
The application of tilt mapping will significantly aid in the advancement of both non-hazardous (drill cuttings and other oil field waste) and hazardous waste disposal by downhole injection. These applications will include: 1) "real-time" monitoring of the actual created fracture geometry allowing injection to be terminated before the fracture grows out of the intended disposal zone, 2) calibration of existing fracturing models by using the diagnostic results, and 3) aiding in the development of new models, if required, for disposal situations.
The combination of surface and downhole tilt fracture mapping determined the location (azimuth and depth) and geometry (height, length and width) of the hydraulic fractures created by injecting drill cuttings. On-site real-time monitoring (with tiltmeters installed in an observation well close to the injection well) indicated that the fractures did not grow out of the target intervals. These results were confirmed by subsequent "core-through" evaluation wells.
The disposal of waste by downhole injection has proven to be an economically and environmentally attractive solution. The key to moving this method forward is to develop and implement technology that will convince the regulatory community that this is safe, reliable, and permanent. Tiltmeter fracture mapping has played a key role to date, and will continue to, in achieving this goal.
Phase Separation Using a Simple T-Junction
Authors: Azzopardi B. J. , Rea S. 
Published: December 2007

Abstract
Gas/liquid flow dividing at a T-junction can exhibit significant phase maldistribution. This has potential as a simple, compact (partial) phase separator. Though there is by now a reasonable body of knowledge on the performance of such junctions, the data is predominantly for air/water at near atmospheric pressures in small diameter equipment. Moreover, there is as yet no agreed criterion to identify at what conditions and for with what geometry a T-junction is a good (partial) phase separator.
This paper presents data from a field trial in which a T-junction was placed on the outlet line from an onshore well. Data were obtained on the phase split at the junction for a number of inlet flow rates and for different resistances in the two outlet legs of the junction. The trends in the data are compared to those for other published work. In addition, a criterion is suggested for good phase separation. The present data, together with that from the literature are then examined and a method for specifying conditions for good phase separation is presented.
A New Approach Solves Differential Sticking Problems in Geleki and Ahmedabad Fields
Authors: Pal Krishan , Mangla V. K. , Joshi N. P. , Tewari P. P. , Bose U. N. 
Published: December 2007

Abstract
Differential sticking is one of the major downhole complications encountered in drilling operations. Generally oil base spotting fluids are used to release the stuck ups. However, the results are not always good.
Based on sticking severity in the laboratory experiments, differential sticking has been classified into two major categories viz.; normal and extreme differential sticking. Sticking of first category can be released by using conventional oil base spotting technique, however, it fails to release the extreme stuck ups which invariably results in operations like jarring, washover, side tracking etc. and leads to loss of considerable precious rig days, costly drill string and/ or loss of the well.
In order to meet the challenges of such extreme stuck ups, a new acid based formulation (Formulation- A) has been developed. It reacts chemically with the cake instantaneously and destroys it. The chemical destruction of the cake leads to the release of both types i.e. extreme as well as normal differential sticking. It has no adverse effect on the properties of drilling fluid and is also non damaging to the drill string.
The two case histories i.e. in the deep well no. GGG, TD- 2900 m. with horizontal drift of 660 m. in the Geleki field and high drift well no. AAA, TD-1835 m. with horizontal drift 904 m. in Ahmedabad field prove the usefulness and effectiveness of this formulation in releasing more than 7 days old severe stuck ups. Said formulation designed in tune with the expected contact area exhibited excellent results with quick release of stuck ups. This technique has since been widely accepted for the use in extreme cases of stuck ups.
Frequently Asked Questions in Well Test Analysis
Authors: Daungkaew S. , Hollaender F. , Gringarten A. C. 
Published: December 2007

Abstract
Despite the tremendous progress achieved in well test analysis in the last twenty years, many important and practical questions that are frequently asked by practicing engineers have received little attention in the literature. Three of these are addressed in this paper. The first one is whether it is possible to obtain more information from build-up data than from drawdown data in a testing sequence. By introducing a new definition of the radius of investigation – as opposed to the radius of drainage – based on the ability to interpret data using pressure derivatives, we show that the information obtainable from a long build-up following a short drawdown is actually limited by the gauge accuracy and noises as the shut-in time increases. The second frequently asked question (FAQ) relates to the minimum amount of detailed rate history which is required in order to obtain correct pressure derivatives, as a truncated or averaged rate histories may modify the derivative shapes at late times and therefore induce erroneous interpretations. A new rule of thumb is proposed, which combines the most recent flow-rate history with an effective time based on a fraction of the cumulative well production. The last FAQ concerns the possibility to distinguish a non-uniform mechanical skin effect from a uniform one from well test data. Current interpretations with fully penetrating wells yield a single value for the mechanical skin effect, which implicitly assumes that damage is uniform over the well surface. Various skin distributions are investigated with a multilayered model to determine how a non-uniform skin distribution around the wellbore affects the interpretation. It is shown that non-uniform skin distribution can be identified during specific flow-regimes and therefore must be taken into account in the interpretation.
Well Testing with a Permanent Monitoring System
Authors: Tibold M. P. , Simonian S. , Chawla M. , Akbar M. 
Published: December 2007

Abstract
An extended welltest was successfully performed on a deep, sour, high-pressure, high temperature remote onshore appraisal well using a permanent downhole monitoring system. Prior to the six-month extended test an initial test and stimulation treatment was performed on the well. The permanent monitoring system provided continuous pressure, temperature and rate measurement data in a technically challenging completion environment. Complete and accurate data was obtained on-line for performance monitoring, reservoir simulation and analytical test analysis. Unforeseen completion challenges and wellbore restrictions would have resulted in alternative conventional data collection methods yielding severely restricted data suites and test results.
Anti-Agglomerant Hydrate Inhibitors for Prevention of Hydrate Plugs in Deepwater Systems
Authors: Frostman L. M. 
Published: December 2007

Abstract
Anti-agglomerant low dosage hydrate inhibitors (LDHI’s) give operators an additional tool for controlling hydrates in their systems. In contrast to kinetic and thermodynamic hydrate inhibitors, anti-agglomerant LDHI’s inhibit hydrate plugging, rather than hydrate formation. Thus anti-agglomerant LDHI’s allow hydrates to form but keep the particles small and well dispersed. Fluid viscosity remains low, allowing the hydrates to be transported along with the produced fluids. Emulsification of the produced fluids is not necessary; in fact, anti-agglomerant LDHI’s have aided in demulsifying several black oil emulsions. In the laboratory, anti-agglomerant LDHI’s have been shown to be effective up to 40 °F below the hydrate formation temperature, at pressures up to 7000 psi, and for shut-ins up to two weeks in duration. In addition, extensive laboratory testing and formulation work have been performed to ensure that the anti-agglomerant LDHI’s are compatible with system metals, elastomers, and treatment chemicals, and that the products will not plug umbilicals nor cause upsets in surface facilities. After a comprehensive laboratory evaluation, an anti-agglomerant LDHI was selected for field testing in a deepwater, Gulf of Mexico oil well. The product protected the system throughout the 1.5 month trial, including two brief shut-ins. This paper presents the results of the laboratory and field tests.
Repeated Seismic Survey From the North Sea using New Streamer Technology
Authors: Eiken Ola , Svendsen Morten , Navrestad Torstein , Haavarstein Erik , Larsen Leif 
Published: December 2007

Abstract
Seismic reservoir monitoring is now a well established technology. The method has a yet unrealized potensial which will open for wider use, if higher repeatability can be obtained. Wider applications could be more quantitative interpretations, monitoring over shorter time intervals and application of the technology to smaller, tighter and more complex reservoirs. Todays towed streamers impose basic limitations on repeatability, as streamer feather is hard to repeat and tow noise must be kept low. New streamer technology, called Q-Marine, involves single hydrophone sensor output instead of hardwired groups, improved acoustic positioning and horizontal steering of the streamers. This enables a better attenuation of tow noise, as induced from either swell or flow across the streamers. The horizontal steering makes repeated streamer positions possible. In the first full-scale use of the system, data will August 2000 be acquired over a major producing field in the North Sea, as a repeat of multi-streamer lines after a time-lapse of three years. This test is expected to show the increased monitoring power of the new system, with detection of only a few meters movement of saturation fronts.