bluuebunny/crossref_metadata_2025 huggingface dataset:
The Effect of Capillary Connectivity Across Horizontal Fractures on Gravity Drainage from Fractured Porous Media
Authors: Stones E. J. , Zimmerman S. A. , Chien C. V. , Marsden S. S.
Published: December 2007

Experimental results for gravity induced drainage from fractured porous media are presented which explore the effect of varying the number of fractures in a given height of medium, the overburden pressure experienced by fracture blocks, and the cross-sectional area of contact between fracture blocks on drainage rate and eventual recovery. Drainage rate and eventual recovery may be increased by a greater overburden pressure, and fewer fractures for a given height of medium. In some cases these factors may also be increased by reducing the cross-sectional area for flow across me fractures. Data are also presented which compare these factors for two different types of rocks. Computer Aided Tomography (CAT scan) results are used to determine saturation profiles for systems of six and twelve fracture blocks. From this work, the effective cross-sectional area of capillary contact across horizontal fractures is identified as a critical factor in both vertical drainage rate and cumulative production from fractured porous media. This experimental basis is then used to explore effective cross-sectional area as a parameter for simulation, which could ease computational requirements for drainage simulation.
Engineering Evaluation and Performance Analysis of the Loop Gas Storage Field
Authors: Wells J. A. , Evans L. J.
Published: December 2007

This paper describes a reservoir performance evaluation of the Yates Sand system underlying the Loop Gas Storage Field, Gaines County, Texas. A PC based numerical simulator was utilized to build a three-dimensional, two-phase operating model for the Yates Sand system. In the course of the study, the reservoir model evolved from a preliminary representation to a validated working model of the field. The model was initially constructed from digitized reservoir data and then adjusted to yield an accurate reproduction ("history match") of the past reservoir performance from both primary depletion and storage operations. After simulating a primary recovery of 12.45 BCF from a reservoir originally containing 13.25 BCF of gas at a discovery pressure of 2841 psig, additional wells were placed in the model and converted for storage calculations. A successful match of the 1981-1989 storage history yielded a Yates Sand system characterization consisting of a main storage zone (C2) and a lower collector zone (C3) which was not currently in communication with the storage wellbores. Several model cases were designed and run to evaluate current field deliverability and future enhancement potential. Based on this model, the storage field has been expanded from a deliverability of 50 MMCF/D and a working gas of 5.0 BCF to a deliverability of 200 MMCF/D and a working gas of 9.4 BCF, with 2.625 BCF of cushion gas being converted to working gas.
Gas Storage Caverns in East Yorkshire Zechstein Salt: Some Geological and Engineering Aspects of Site Selection
Authors: Knott Iain , Cross K. G.
Published: December 2007

Natural gas has been stored in underground salt cavities in the UK since 1979: for ‘peak shaving’ purposes to supplement demand from the high pressure National Transmission System. Solution mining of the salt cavities began in 1974. This existing facility is known as the Hornsea Installation and is located on the East Yorkshire coast.

The identification of the need for an additional greenfield storage site, together with the geological problems encountered at the Hornsea Installation led to a geological appraisal of the Permian Zechstein salt along the coastal strip of East Yorkshire.

The paper briefly describes the process facilities and engineering requirements at the existing facility for development of salt cavities and then summarises the criteria that were established in a feasibility study, to select a new site location.

A geological evaluation of existing well control and available seismic data in the coastal area was carried out on the basis of required thickness of salt and purity. The paper highlights the results of this study concentrating on the use and limitations of existing seismic and borehole data in quantifying and modelling loss of salt in the At wick 4 well at Hornsea and the inability to detect highly soluble carnalitic salts using seismic methods.

Seismic analysis has indicated that several potential sites previously thought to have been acceptable are now considered as unsuitable for cavern development but the identification of a suitable site in a previously unconsidered area to the South has reduced associated geological risks for cavity development.
Temporary Storage of Natural Gas in Coal Wells
Authors: Puri Rajen , Volz R. F.
Published: December 2007

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

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

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

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

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

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

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

"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

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

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

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

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

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

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

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.
The Rotating Deoiling Cyclone: Recent Development and Operating Experience
Authors: Triponey G. , Woillez J. , Bezard C.
Published: December 2007

Since its presentation in 1987 (Ref 1), the rotating de-oiling cyclone has been proven as a technical competitor to existing de-oiling equipment.

Extensive trials in 1989-1990 by an independent testing laboratory using a size 2 (2500 BWPD) rotating cyclone in parallel with a static cyclone and a flotation unit (Ref 2), and a field test with a size 2 and two static cyclones (Ref 3) have demonstrated the superior separation capability of this equipment.

However, in order to answer to the criticism concerning the mechanical reliability of this equipment due to the fact that it is a rotating machine, a one year extended mechanical test has been carried out with a size 2 unit on a petroleum field near Paris, with good results.

At the same time, the need for a larger capacity cyclone led to the construction of a size 4 (10 000 BWPD) rotating cyclone. This cyclone has been hydraulically tested with satisfactory results. The mechanical design is different from the size 2 and uses hydrostatic bearings in order to improve the reliability. This unit will be installed on a North Sea platform by the end of 1992, for full capacity field testing and performance evaluation.

The rotating cyclone has been mathematically modelled and the results compared with the laboratory and test loop data. The model will be used to explore the behaviour of the cyclone in specific ranges of operation (oil concentration and flowrates) and to optimize the inlet/outlet geometry.

Application of rotating cyclone is not limited to produced water de-oiling; it can be applied also to dehydration of crude oil. The results of laboratory trials carried out on the pilot unit are also presented.
The History of Horizontal Wells in the V Fields
Authors: Robertson C. J. , Rapach J. M. , Grant N. T. , Smith M. H.
Published: December 2007

Six horizontal wells have been drilled in the V Fields reservoirs with a further two wells planned to be drilled in 1992. Several objectives pursued by these wells include,

Increasing the probability of penetrating a high permeability sand body in a heterogeneous formation. Increasing deliverability by extending the length of contact of the well with the formation. Draining low relief, flank areas of the field. Accessing multiple, potentially isolated fault compartments.

The degree of success has been mixed. Some wells surpassed their objectives while others have been disappointing. Regardless of the commercial results, every well has provided a major insight into the reservoir dynamics and description of these complex fields.

The results show that,

Accurate reservoir description is important to a successful well. Horizontal wells appear to improve the chances of attaining commercial gas production rates from heterogeneous formations. Deliverability can be enhanced by extended formation contact in both good quality sands and individual high permeability features. Compartmentalisation may affect V Fields reservoir performance but faulting is less important than sedimentary heterogeneity.
Feasibility Study for a Horizontal Well in a High-Pressure and Temperature Environment
Authors: Santarelli F. J. , Dardeau Claude , Zurdo Christian
Published: December 2007

When planning the development of a new field, the potential of horizontal wells is systematically investigated from a reservoir engineering point of view. Yet, from a drilling point of view, the feasability of such wells must be questionned. When reservoir temperature and pressure are high, the margin of admissible mud weight which will avoid kicks and yet not lead to mud losses becomes very narrow and may even prohibit the drilling of such wells. This paper describes such a study and shows how log and core data from vertical appraisal wells can be interpreted and used in various models to determine such a margin.

After estimating precisely, in situ stresses and rock mechanical and thermal properties, a first margin of admissible mud weight is calculated.

This first result is then modified to account for the effects of mud temperature and circulation which are also modelled. The model results are calibrated against an FMS log on a vertical well showing drilling induced hydrofractures which corresponded to mud losses in certain formations. The paper concludes at the feasability of the well provided certain tripping practices and mud monitoring techniques are used.
Process Optimization for an Oil Field Under Gas Injection
Authors: Bu Tor , Berge Lillian , Solsvik Olav , Overaa Sverre
Published: December 2007

The Oseberg oil field is produced by immiscible gas injection. Produced gas is reinjected, and the pressure is kept almost constant by additional injection of gas imported from the nearby giant Troll gas field. The so called TOGI scheme is described in another paper presented at this conference [1]. Fig. l gives a schematic representation of the field development.

By installing a Dew Point Control module (DPC) there is a potential for increased condensate production, which again leads to injection of a leaner processed gas (higher methane content). The question is if this early gain in liquid production could be offset by a reduction at a later stage.

As the lean injected gas mixes with the gas cap gas the liquid content of the gas decreases. When the injected gas contacts the oil component exchanges between the oil and the gas phase take place. In addition, compositional variation will occur during periods of pressure depletion. Such effects are demonstrated in a series of PVT experiments, reported in a previous paper [2].

Another important issue is the quantification of the total condensate (oil from gas) production, which in this case will add significant reserves to the previously estimated oil production.

In this work we explain how a multidisciplinary approach, combing process simulation, Equation of state PVT simulation, compositional and black oil reservoir simulation; leads to quantitative estimates of compositional effects.

The emphasis is on method rather than on quantitative results. We discuss the simulation tools that have been applied, how the required input data are generated, and how the component exchanges in the reservoir and various simulation artifacts may affect the results.
Effect of Low Interfacial Tensions on Relative Permeabilities in Some Gas Condensate Systems
Authors: Ronde Hidde
Published: December 2007

This paper shows that a C1-C3 near-critical fluid system goes through a Cahn transition(at an IFTC1-C3 = 03m N/m), the latter value being based on pendant drop-measurements on a 2,6-lutidine-water model system and the application of critical scaling principles.

A Cahn transition into a perfect wetting regime is not just a transition from very good wetting to perfect wetting in the capillary sense. This is a consequence of the fact that for near-critical fluids in thermodynamic equilibrium the solid(channel) wall is an essential part of the system that is in thermodynamic equilibrium, leading to a redistribution of phases in the hydraulic channels, whereas the spreading coefficient becomes essentially zero for such a system. When viscous forces are dominant this leads on its turn inside the Pressure-Composion Cl-C3-(Berea) phase envelope to a core-annular ("film-flow") regime for the bigger channels. The smaller ones go upon pressure depletion through a noticeable transition region outside this envelope, causing capillary condensation, that might start in the millidarcy-range. At the Cahn transition inside the envelope relative permeability curves of the Cl-C3(Berea) system straighten. In the filmflow-regime an Einstein emulsion contribution to relative permeability is clearly identifiable at the saturation extremes leading to asymetric straightening of the relative permeability curves.
Improved Formation Evaluation and Borehole Stability of Ovalized Wellbores
Authors: Berger Pierre , Williams Leon
Published: December 2007

A large percentage of boreholes drilled in the Mahakam delta area in East Kalimantan are adversely affected by tectonic stress. Stress imbalance in the borehole results in enlarged and elongated holes and borehole breakouts in the shales. Pad type logging devices are seriously affected by such borehole conditions.

The use of a short axis logging kit enables good logging data to be acquired in such boreholes. The stress imbalance can be minimized, by optimizing mud weights used in drilling, through estimations of in-situ stress and mechanical properties obtained from shear sonic logging data.
Simulator for Predicting the Mobara-Type Production Performance
Authors: Tazaki Yoshiyuki , Yamazaki Toyohiko
Published: December 2007

Mobara gas fields are dissolved-in-water natural gas fields which exist in Minami-Kanto. The wells of Mobara gas fields have particular production performance curves called "Mobara type". The GWR (Gas Water Ratio) curves of Mobara type production perfor-mance are initially low, and then increase to be so high as to blow up a large amount of water.

The deposits are restricted to Kazusa group consisting of alternate thin layers of sandstones and silty mudstones. The gas is indigenous to Kazusa group. Most of the gas generated in silty mudstones is dissolved in the formation water. A little of the gas is distributed as discontinuous globules due to pore throats in silty mudstones.

The bubbles begin to move toward sandstones when the formation pressure has been reduced. The authors elucidated the flow mechanism and constructed the sand/silt system. In the mechanism silty mud-stone properties are very important, especially relative permeabilities and capillary pressures.

The reservoirs of Mobara gas fields are a dual porosity type. The authors developed a production estimation simulator which is combined with a gas-lift calculation program. It is useful in simulating Mobara type production performance.
Optimal Oilfield Development of Fields With a Small Gas Cap and Strong Aquifer
Authors: Behrenbruch Peter , Mason L. T.
Published: December 2007

Production practices for oil fields with gas caps usually centre around Conservation of the gas cap (energy) to maximise oil recovery. A less conventional but effective reservoir management approach involves an early gas cap blowdown phase in situations where the gas cap is small and a strong aquifer is present.

This paper describes the critical parameters and the benefits from a less orthodox depletion plan. After discussing this subject from a general point of view, the reservoir management plan for the Skua Field, located in the Timor Sea, is cited as a successful application.
Neural Network-Based Formation Parameters Estimation From Well Logs in Quantitative Log Analysis: A Comparative Study
Authors: Zhou Cheng-Dang , Wu Xi-Ling
Published: December 2007

Accurate estimation of formation Parameters from well logs is essential to quantitative log analysis. The conventional log analysis techniques are largely dependent on the initial assumptions about log analysis Parameters. However, without any assumptions and mathematical raodels, neural network(NN) based formation parameter estimation approaches can quickly estimate formation Parameters directly from well logs after successful training.

In this paper, a four-layer feedforward neural network, and a neural model of principai component analysis and linear regression are used to estimate porosity from well logs. And a model-based Inversion of well logs and a principai component regression algorithm are used for comparison with the above two neural approaches.

Severai examples from a Chinese oilfield demonstrate the NNs-based approaches' advantages over the conventional methods in estimating formation Parameters from well logs. Even though the results show that the estimates of formation Parameters from the four-layer NN approach are in the best agreement with the core data, when applying to different wells with complex geological structures, this four-layer NN approach often fails to give satisfactory and consistent results. In consideration of such limitation of a single net, the paper presents an integrated approach to solve this problem.
An Enhanced Recompletion Design Methodology for Vertical, Inclined, and Horizontal Wells
Authors: Ahmed Usman
Published: December 2007

Upon initial completion, a good number of wells (vertical or horizontal nor inclined) typically do not produce at expected flowrates. To remedy the situation, an effective re-completion design is needed that can address the various components of wellbore total skin associated with faulty and/or inadequate completion. Important components of total skin include mechanical skin (wellbore damage), partial completion and ineffective perforation or gravel pack. Reduced well production due to partial completion will not be remedied by an effective acid job. Also, by increasing the perforation interval, one may not be able to remedy problems associated with wellbore damage.

In this paper we present a technique that can allow one to differentiate between the various components of wellbore total skin and thus provide the opportunity to design an effective and optimized re-completion design. The technique involves integration of petrophysical log and well test derived permeability with either production or injection profile data. The paper concludes with a field case study to illustrate the application of the technique.
Transient Wellbore Pressure and Flow Rates in a Commingled System With Different Layer Pressures
Authors: Shah P. C. , Spath J. B.
Published: December 2007

This work addresses the problems of design and interpretation of layered reservoir tests (LRT) in commingled wells when the layer potentials are different; the difference may be in the conditions either at the initial time or at the outer layer boundaries. The multilayer models for commingled wells are constructed from existing single-layer analytic solutions to account for different layer properties and boundary conditions. A general situation is considered in which some layers have a constant pressure condition and others have a no-flow condition at the outer boundary. The algorithms developed here will allow the reservoir engineers, for the first time, to rigorously design and interpret the multi-transient LRTs using the extensive catalog of existing single-layer analytic models, rather than relying on numerical simulation. This development will not only save a great deal of computer time, but will also enable interpretation of tests in reservoirs whose geometries and parameters place them beyond the capability of existing simulators.

An LRT design consists of calculating the transient wellbore potential and the individual layer rates for a given variation of the total flow rate. Two alternative scenarios are considered for the initial state of the reservoir: Either the reservoir is in equilibrium and the well is put on production at t=0, or the well is initially producing in a steady state. Algorithmic procedures are derived from the first principles and validated by comparison with the results of finite difference numerical simulation for three different reservoir systems. A fourth example, which is beyond the capability of simple reservoir simulators, is presented to demonstrate the power of the new procedure.

The LRT interpretation requires the calculation of the total and individual layer flow rates during a multitransient test, given the measured wellbore potential over the test period and the production history of the well. The scheme presented for this problem relies on a synthesis of the new test design calculation procedures with the existing algorithms for flow rate calculation.
Formation Permeability Determination Using Impulse-Fracture Injection
Authors: Gu Hongren , Elbel J. L. , Nolte K. G. , Cheng A. H-D. , Abousleiman Younane
Published: December 2007

"Impulse fracture" is an injection test used to determine formation permeability and reservoir pressure. The test consists of a small-volume water injection to create a short fracture and a shut-in period afterwards to record pressure falloff. The pressure falloff after fracture closure is used to deduce permeability and reservoir pressure. The fracture can pass the near-wellbore damaged area and have the true formation exposed to flow transients. Also, fracturing may sometimes be difficult to avoid for injections in low-permeability formations.

The theory and analysis of impulse fracture are based on an instantaneous-source solution to the diffusivity equation. Numerical simulation examples and field case studies are used to support the validity of the analysis. The applicability of impulse fracture in gas reservoirs is demonstrated by numerical simulation results from a multi-fluid-bank simulator and by field cases. The impulse-fracture injection test is an economical and simple means to determine formation permeability. The test can be conducted in conjunction with mini-fracture or micro-fracture stress-test injections.
Laboratory Measurement of Critical Rate: A Novel Approach for Quantifying Fines Migration Problems
Authors: Miranda R. M. , Underdown D. R.
Published: December 2007

Formation Damage resulting from the migration of small, mobile mineral particles within hydrocarbon producing formations has been, and continues to be a major concern of drilling and production engineers. The flow rate at which these small, usually colloidal, particles begin to dislodge and move within a formation is referred to as the critical flow rate.

Many factors can influence the migration of fines within a producing formation: mineral composition, size and shape; pore throat size and distribution; relative fluid saturations; particle wettability; viscosity of the mobile fluid phase; fluid interfacial tension; production rate; and chemical alteration by drilling and completion fluids can affect the mobility of mineral species responsible for formation damage from in situ fines migration. A novel approach for the analysis and quantification of formation damage resulting from fines migration is described in this paper. The analysis is routinely performed on core plugs from whole core, rotary sidewall cores, and percussion sidewall cores. The technique described employs industry accepted practices for the measurement of single and multiphase permeability of core samples at reservoir conditions, as well as a novel experimental methodology and data processing technique for critical rate determination. A baseline permeability is established at a very low production rate. The rate is subsequently increased in a step wise fashion, returning to the established base rate after every consecutive rate increase. Experimentally derived flow rate and permeability data are converted to bottom hole and wellhead production rates using completion data and well geometry.

The technique described in this paper is used successfully to augment production efforts in several producing formations by integrating the data obtained from flow studies with X-ray diffraction, scanning electron microscopy, and petrographic analysis.

By imparting the ability to vary drilling and completion procedures while under simulated reservoir conditions in the laboratory, this analytical technique can reduce the risk of formation damage at all stages of well operations.