bluuebunny/crossref_metadata_2025_split huggingface dataset:
Temporary Storage of Natural Gas in Coal Wells
Authors: Puri Rajen , Volz R. F. 
Published: December 2007

Abstract
A research project, nicknamed "ReGas," has been initiated to determine the technical and economic viability of using coal wells to temporarily store surplus methane gas. Coal wells are being tested to determine methane injectivity and flow back characteristics.
Based on computer simulated studies, ReGas has several potential applications. ReGas could be used as a "shock absorber" to insulate gas fields from short term fluctuations in downstream operations. Furthermore, preliminary scoping economic analysis suggests that, if almost all of the methane injected into a coal well can be recovered, ReGas offers profit opportunities from predictable changes in gas prices (say from summer to winter months). Furthermore, ReGas could conceivably minimize water influx problems caused by shutting in coal wells for a prolonged period of time. Control over gas deliverability could also provide a gas field operator greater flexibility, which may improve operating efficiency.
Results from two short (7 days) ReGas pilot tests are presented, and one field performance is simulated using a computer model. Longer term field tests are needed, and are planned. The impact of prolonged high rate gas injection on wellbore skin is also being studied. Some of the factors that may impact the viability of a coal well to temporarily store natural gas are discussed.
Selective Treatment of an Openhole Gas Storage Dolomite Reef Structure Under Pressure
Authors: Chown J. S. , Holland J. J. , Burtner J. C. 
Published: December 2007

ABSTRACT
A new well was drilled in a dolomite reef gas storage field to add deliverability to the unit. Wellbore damage had occurred to the open hole production interval from the drilling process and a remedial acid treatment operation was required. To effectively treat the open hole interval a unique resettable inflatable straddle packer system was developed to selectively place the acid along the open hole interval. The straddle packer system required new running procedures to be adopted which utilized snubbing and wireline operations.
The selective placement of the acid treatment proved to be necessary, effective and economical.
Inflow Performance of Horizontal Wells in Multilayer Reservoirs
Authors: Kuchuk F. J. , Saeedi Jawaid 
Published: December 2007

Abstract
The inflow performance formulas for horizontal wells presented in the literature are all for single-layer reservoirs. This paper presents formulas for evaluating the inflow performance of horizontal wells in vertically layered reservoirs with crossflow. The system has a rectangular drainage region in the x and y directions and is bounded at the top and the bottom by horizontal planes with no-flow and/or constant-pressure boundary conditions. The well is located anywhere within the drainage volume and could be of any length.
Analytical models for dynamic (transient), pseudosteady-state, and steady-state productivity indices for horizontal wells in layered and bounded reservoirs are developed. They may also be used for the analysis of transient pressure or flow rate data, and both from horizontal wells in bounded systems.
We present a method for the selection of the well location in a layered system for maximizing the productivity index. We also show that in a layered system with variable vertical permeability distribution, the proper selection of the well location is important for maximizing the productivity. The layering effect for most systems may not be treated as a single layer with average properties. The vertical permeability of each layer is the controlling parameter for the productivity.
The productivity model developed may be used as a screening tool before or during drilling to obtain the best well location for a horizontal well. It can also be used to fine-tune numerical simulators for horizontal wells in layered systems.
Evaluation of In-Situ Geochemical Tracers and Their Implication for Production at a South Midway Sunset Heavy Oil Reservoir
Authors: Perkins E. H. , Young B. K. , Gunter W. D. , Turner J. C. 
Published: December 2007

ABSTRACT
The geochemistry of the produced water from the steamflood at the MOCO Monarch anticlinal steam-drive pilot in the South Midway Sunset Field, Kern County, California was evaluated to yield information about reservoir flow patterns, reservoir temperatures and correlation with oil production. Dissolved chloride, bromide, boron and silica concentrations in production waters can be used as natural in situ tracers. Chloride and bromide are inert and their concentrations reflect the mixing of injected and formation waters in the reservoir. Silica and boron are reactive tracers; the concentration of silica reflects the reservoir temperature and boron the extent of reaction with the Monterey diatomite which is thought to form a barrier to steam between the B and C zones.
Analysis of the concentrations of chloride and silica produced from wells perfed in each zone as a function of time and well location was made. The effects of the anticline and structural features controlling communication paths can be clearly seen in the chemical data with some of the variations clearly the result of small scale heterogeneities. Communication paths are well developed in a northeast south-west direction in both zones. Communication has been developed in the south end of the pilot. Silica concentrations indicate that the C zone is hotter than the B zone. Generally the maximum oil production correlates with the wells with high produced chloride concentration and low produced silica concentration (good communication, but locally low temperature). These wells produce significant amounts of oil for some time after both the chloride and silica values have increased. After the producing zone has been swept, oil production drops, and both the chloride and silica concentrations are high. The final decrease of chloride while maintaining high silica values indicates the steam front is near the producer and if it has not already, that oil production will decrease rapidly.
Improved Cement Placement on North Sea Wells Using a Cement Placement Simulator
Authors: Ryan D. F. , Kellingray D. S. , Lockyear C. F. 
Published: December 2007

ABSTRACT
A new computer based cementing simulator is described that quantifies the effect of key displacement variables such as geometry, standoff, fluid rheology and density, and flow rate. The paper shows how to optimise cement placement within the fracture and pore pressure constraints of the well and demonstrates its use through case studies from the North Sea. The technique assesses the quality of mud removal and cement placement as well as estimating the circulating pressures throughout the job. The examples illustrate how existing rules of thumb can be confusing and how reliable cement jobs can be achieved through quantitative design procedures.
3D Modelling of Gravel-Pack Structure and Its Application to Optimum Gravel-Size Selection
Authors: Ren Guowu , Oyeneyin M. B. , Peden J. M. , Bigno Yann , Hosseini Ali 
Published: December 2007

ABSTRACT
In this paper, the basic concepts of a 3-D random gravel packing modelling technique being developed to simulate typical gravelpack structures are presented. This is a followup on the 2-D modelling technique which was initiated in the Department of Petroleum Engineering at Heriot-Watt University as part of an on-going project On optimum gravel sizing for effective sand control.
The 3-D modelling is based on the simple probability concept in which the gravelpack structure is simulated in three dimensional format by modelling the deposition or settling of gravels one at a time. The resulting gravelpack structure is thereafter evaluated for stability and the resulting pore throat size distribution is evaluated using a purposely developed computer code. The program goes further to evaluate the maximum pore throat distribution and the resulting porosity and permeability of the simulated gravelpack. The maximum pore throat size distribution is here taken as the minimum size of the formation fines that can be effectively controlled by the commercial gravel.
Specific case studies have been carried out for typical commercial gravels the results of which are presented.
Comparisons are made between the 3-D model predictions and those obtained from the preceding 2D model. The 3-D model not only provides a better appreciation of the geometry of the gravelpack structure but also gives a more realistic prediction of pack porosity and permeability when compared with experimental results. The maximum pore throat distribution as predicted by the 3-D model were found to be larger than the equivalent 2-D predictions for all the commercial gravels considered.
Overall, the results have demonstrated that simulation of the gravelpack structure is a very effective technique for probable gravel size selection and is a promising tool for the setting of optimum size distribution criteria for different commercial gravels.
The concept of gravelpack structure simulation forms an integral part of a comprehensive gravel size selection strategy involving the development of a computer package for optimum gravel sizing, a summary of which has also been presented.
Quantification of Macro- to Megascale Reservoir Heterogeneity: A Practical Approach Based on Computer Mapping Techniques
Authors: van de Graaff W. J. E. , Bentley M. R. , Kortekaas T. F. M. 
Published: December 2007

ABSTRACT
A new "quick-look" method for quantifying reservoir heterogeneity was developed, using data from the Cormorant Field in the Brent Province in the northern North Sea. The "Reservoir Heterogeneity- Measure" (RHM) technique is based on combining three parameters that describe sand quality (net/gross ratio, porosity and permeability), two parameters that describe geometric aspects of the reservoir (sand-body geometry and faulting) and one parameter that describes the effectiveness of reservoir compartmentalisation (fault sealing).
RHM maps combined with conventional "bubble" maps of produced volumes are of use for quick-look ranking of remaining oil targets as the RHM values for the areas of interest reflect producibility of the remaining oil volumes.
The technique should be directly applicable to other fields in the same province as well as to fields in analogous geological settings.
Stochastic Modeling of Wormhole Growth in Carbonate Acidizing With Biased Randomness
Authors: Pichler Thomas , Frick T. P. , Economides M. J. , Nittmann Johann 
Published: December 2007

ABSTRACT
"Wormholes", which are characteristic shapes resulting from the acidizing of carbonate formations have been considered in the past as fractals. In previous publications, analytical relationships of the area penetrated by wormholes, the wormhole porosity and the fractal dimension have been presented. Local mineral compositional heterogeneities and structures result in uneven reaction profiles when acid reacts with carbonate rocks. This, coupled with permeability heterogeneities, leads to microscopic flow instabilities which may evolve into macroscopic wormhole patterns.
The understanding of the physics of acidizing is becoming a serious issue with the emergence of horizontal wells, where massive volumes of acid may be needed for effective stimulation. The stochastic nature of the wormholing process has been a limiting factor for a physical interpretation. The simulation of this unstable growth process is the purpose of this paper.
The impacts of permeability anisotropy, heterogeneous distribution of the properties of the formation, such as microfractures and zones of different permeabilities, are investigated. A simulation model, the permeability driven fingering model (PDF) is presented. This technique is a new approach to diffusion limited growth, which traditionally has been simulated with diffusion limited aggregation models (DLA). The randomness of fractal growth is changed by introducing a bias representing the permeability anisotropy and the preferential reaction kinetics of lithologic heterogeneities.
Anguille Marine, a Deepsea-Fan Reservoir Offshore Gabon: From Geology Toward History Matching Through Stochastic Modelling
Authors: Giudicelli C. B. , Massonnat G. J. , Alabert F. G. 
Published: December 2007

ABSTRACT
The ANGUILLE MARINE field has been produced for 25 years. Implementation of water injection soon revealed complex reservoir mechanisms controlled by severe sedimentary heterogeneities.
The ANGUILLE Formation has been deposited in a deep-sea- fan environment (slope apron) with a low sand/shale ratio. In such an environment, the geometry of sandbodies controls the reservoir connectivity. Knowledge of this parameter is therefore critical in understanding flow mechanisms.
This paper deals with a multi-scale analysis of the heterogeneities (5 scales were studied), and the research of the best way to represent all the scales in the 3D modelling.
Sequence stratigraphy principles are applied successfully and allow the reconstitution of the ANGUILLE Formation history. In each defined time unit, a sequence analysis log data is used to divide the reservoir into four main types of turbiditic geometries (channels, lobes, slumps, laminated facies). Isovalue maps of lobe and channel frequency slow clearly the paleo-directions of sediment supply. These, together with the well data, constrained the generation of fine 3D models of heterogeneities (more than 2 millions gridblocks) using geostatistical techniques. The generated models proved to efficiently represent the reservoir, as confirmed by the drilling of a new well in the northern part of the field. The results of the full-field flow simulations raised several questions regarding both the geological model and the upscaling process. The use of partial models led to the conclusion that the aggregation rate should be optimized before using some geological characteristics (sedimentary bodies dimensions, elementary facies permeability,…) as parameters in the history matching process.
Reservoir Management of the Dulang Oil Field, Offshore Peninsular Malaysia: The Heuristic Approach
Authors: Hussain Ahmad , Egbogah E. O. , Hovdestad W. R. 
Published: December 2007

ABSTRACT
This paper describes reservoir management practices for the early development stages of the Dulang oil field, a multiple reservoir field offshore Peninsular Malaysia. The Dulang field is located approximately 130 kilometres offshore Kuala Terengganu in a water depth of about 76 metres in the South China Sea. The reservoir sands are of late Miocene Age and exhibit a complex stratigraphic layering within an elongated anticline divided by numerous faults. Two platforms are onstream at an average rate of 45,000 barrels of oil per day. The third and fourth platforms are scheduled to go onstream by late 1993, and late 1994 concurrent with planned pressure maintenance operations in late 1994. The understanding of the reservoir performance gained from all stages of the field development will be used to define the ultimate reservoir management strategies. Pressure maintenance operations were deliberately deferred in view of anticipated geological complexity. The geological complexity, multiple completion, reservoir variation and varying depletion mechanism necessitate prudent reservoir management practices in the Dulang field.
The overall reservoir management strategy developed for the Dulang oil field may entail up to fifty separate depletion plans for identified reservoir units. Individual wells and reservoir units have been ranked according to quality and productive potential. Quantitative guidelines for reservoir quality, utilising site specific factors, have been developed and applied on an ongoing basis. This paper also presents the scope of the reservoir description and surveillance guidelines, performance monitoring procedures, data acquisition and analysis, which collectively serve as the basis for formulating optimum reservoir management strategies in this field. Logistical considerations with respect to operational simplicity and flexibility were also incorporated into the field development and reservoir management plans.
Management of a North Sea Reservoir Containing Near-Critical Fluids Using New Generation Sampling and Pressure Technology for Wireline Formation Testers
Authors: Reignier P. J. , Joseph J. A. 
Published: December 2007

ABSTRACT
This paper presents the first application of a new wireline formation tester, the Modular Formation Dynamics Tester (MDT*), that successfully recovered bottomhole samples of a near-critical reservoir fluid. The tester device achieved this by controlling and minimising the pressure drop during sampling; in some cases just 0.5 bar was sustained. Full PVT laboratory study confirmed the purity and representativity of samples taken in this manner from two wells. Variations in the fluids’ properties with depth as determined from samples taken during DST's on older wells were subsequently revised to take into account this newer, more accurate fluid description.
The decision to sample a near-critical fluid using this wireline tester on the first well involved an element of uncertainty since such an operation had never been attempted before. However, in the case of the second well the decision was based on the knowledge and experience gained from the first, where overall performance of the tester and PVT quality of the samples were excellent. In fact, sampling in openhole with a wireline formation tester as explained above actually allowed dispensing with planned DST's in both wells, and hence proved to be a very cost-effective solution.
The same wireline tester that was used for sampling comes equipped with a new single-crystal quartz gauge, which displays quartz sensor accuracy and resolution but performs like a strain gauge in terms of dynamic response characteristics. Pressure profiles interpreted in all wells in the field, including data from the new quartz gauge, exhibit the typical characteristic of critical to near-critical reservoir fluids - no discernible gas-oil contact. The reservoir management implications of this result are discussed in the paper.
Enhancing Gas Reservoir Characterization by Simulated Annealing Method (SAM)
Authors: Ouenes Ahmed , Meunier Gilbert , Pelce Veronique , Lhote Isabelle 
Published: December 2007

ABSTRACT
Recently Ouenes et al.1–4 used extensively simulated annealing to generate permeability and porosity fields. In this paper, the Simulated Annealing Method (SAM) is applied to a gas storage reservoir. The permeability field predicted in four geological layers preserves the spatial distribution and honors the actual measured data from the field. These known data at the wells lead to isotropic and anisotropic variograms which were matched by SAM. In this approach, contrasting the usual conditional simulation, no interpolation technique is used to smooth data at unknown locations. The generated field is compared to a kriged field by using a 3D advanced gas reservoir simulator. When using permeability fields generated by SAM, gas and water pressure data obtained through simulation become very close to observed field pressure data. On the other hand, the pressure obtained with the kriged field clearly shows that the smooth representation introduced by the kriging is not realistic, and the heterogeneities which affect considerably the flow behavior are not well described.
Sole Pit: Improving Performance and Increasing Reserves by Horizontal Drilling
Authors: Mulder Gerard , Busch V. L. P. , Reid Ian , Sleeswijk Visser T. J. , van Heyst B. G. 
Published: December 2007

ABSTRACT
Shell U.K. Exploration and Production, operator in the U.K. sector of the North Sea for Shell and Esso, is developing the tight gas reservoirs of the Barque and Clipper fields, located in the Sole Pit Basin of the U.K. Southern North Sea. Well productivity is fundamentally dependent on the intersection of dune slipface sands and/or sparsely distributed open natural fracture systems. The initial development plans were based on the use of conventionally deviated wells with cemented liners across the pay section, relying on massive hydraulic fracture stimulation, if required, to achieve economic production rates. This concept has progressively evolved towards the use of horizontal wells which increase the probability of intersecting the productive features in the reservoir. Twelve horizontal wells were drilled up to mid 1992, out of a total of twenty six development wells. The main findings are:
– average initial deliverability of horizontal wells is significantly higher than that of conventionally deviated wells; Productivity Improvement Factors of between 2 and 7 have been realised; – horizontal wells decline more slowly than fracture stimulated wells; – Ultimate Recovery has increased by 20% relative, which is to a large extent due to horizontal wells; – the well count can be reduced by some 25%; this has, in combination with well cost savings through the use of slim casing schemes and the increase in UR, significantly improved the project economics; – additional reserves from low relief flank areas can be accessed.
The Potential to Increase UKCS Hydrocarbon Recovery Using Advanced Recovery Techniques
Authors: Foulser R. W. S. 
Published: December 2007

ABSTRACT
The potential to improve future oil recovery from UKCS fields has been evaluated in a systematic study of the application of advanced recovery methods in nearly 70 oilfields. The methods considered are gravity stabilised gas flooding, horizontal gas flooding (WAG), chemical flooding and the engineered depressurisation of reservoirs late in life.
Without considering the UKCS fiscal regime, but demanding a positive NPV at a 15% discount rate, the potential ranges from 0.3 Bstb to 3.1 Bstb for oil prices in the range $16 to $48/bbl. Most of the potential, 2.4 Bstb, is realisable at an oil price of $24/bbl.
The exposure, NPV and IRR of advanced recovery projects and current UKCS developments are compared. This shows that most advanced recovery projects are less attractive than new field developmen's. This assessment is exacerbated by the increased uncertainties involved in the application of advanced techniques and the UKCS fiscal regime which disadvantages late investment in mature PRT paying fields.
The main reservoir engineering and process description uncertainties associated with the advanced recovery techniques have been highlighted by the study. These provide a focus for future R&D effort.
36-in. Gas Pipeline Riser Replacement and In-Situ Valve Repairs Using a Cost-Effective, High-Pressure Isolation Estopple Technique
Authors: Nespeca G. A. , Nummedal T. A. 
Published: December 2007

ABSTRACT
During the August 1991 Maintenance Shutdown of the Ekofisk Field, the 36" riser for the Ekofisk-Emden Gas Transmission Pipeline and a 70 m section of the subsea pipeline downstream of the 2/4 Riser platform were replaced in their entirety. The need for replacement was due to subsidence of the seabed due to reservoir compaction which had resulted in riser movement and deflections that would have caused unacceptable level of stress in the riser without implementing the remedial repair program.
The hydroplug sealing device utilized to isolate the pipeline was a three-module modified version of earlier two-module hydroplug designs used in 1981, 1984 and 1987 for various riser and valve repairs on the Ekofisk-Emden Pipeline Transportation System. The redesign of the hydroplug included the addition of a third module used for centralizing the umbilical in the pipeline and modifications to both the slip and seal modules to ensure positive sealing in the 3 mm thinner walled subsea line pipe.
This paper describes the project premises and planning, the required hydroplug modifications, verification testing and the actual performance of the hydroplug deployments necessary to isolate the P/L during the riser replacement and valve repair program. This is the first known field procedure where subsea habitat welding activities have been conducted behind a high pressure gas barrier plug.