bluuebunny/crossref_metadata_2025 huggingface dataset:
From Disposal at Sea to Distribution of Oil-Based Cuttings
Authors: Bohm J. T. C. , Laan L. v. d.
Published: December 2007

The environmental impact of cutting discharges has led to a significant change in the way oilbased mud has been used at the Dutch Continental Shelf (DCS). The industry has converted from direct disposal of oilbased cuttings to a zero oil disposal at sea by transfer of cuttings to land. Moreover, distillation of cuttings has resulted in a closed-loop application of the base oil. This method has been developed as a standard operation even before the zero oil disposal limit became effective in 1993. Although the well costs have increased with 2.5 % as a result of the new requirement, the extra costs amount to only a small fraction of the extra well costs if only waterbased mud would be allowed. Both industry and environment benefit and it has resulted in an increased use of oilbased mud since 1991 at the DCS. Further scope for reduction of environmental impact related to waste disposal is limited. The remaining concerns are related to the prevention of oil spills.
Water-Based Glycol Drilling Muds: Shale Inhibition Mechanisms
Authors: Aston M. S. , Elliott G. P.
Published: December 2007

Water based glycol (polyol) muds are becoming increasingly popular, and are now replacing oil based muds in many drilling operations. Apart from exceptional shale inhibition, other benefits include environmental friendliness, ease of handling, robustness and good lubricity.

This paper explores the mechanisms of shale stabilisation by glycol muds. Experimental data show shale dispersion, swelling and hardness behaviours for a model reactive shale (London Clay). The data suggest the high level of inhibition obtained is mainly due to a shale hardening effect - the shale actually becomes harder than in its original state. Measurements with a range of salt types show that salt (eg KC1) plays a major role in the inhibiting mechanism.

Adsorption measurements indicate that the glycol displaces water from the shale, resulting in a change in pore fluid composition. In effect, the glycol acts as a penetrating glue which, it is believed through hydrogen bonding effects, strengthens the shale. This mechanism contrasts with other water based mud additives (e.g. PHPA or polyamines) which form a protective or encapsulating layer on the surface of the shale.
The Formulation of Milling Fluids for Efficient Hole Cleaning: An Experimental Investigation
Authors: Ford J. T. , Oyeneyin M. B. , Gao Erhu , Williamson R. S. , Peel L. C.
Published: December 2007

This paper describes a set of experiments, sponsored by Mobil North Sea Ltd (MNSL) and conducted at Heriot-Watt University, which were designed to investigate the carrying capacity of milling fluids. The objective of this work was to determine the fluid rheology which would most efficiently transport debris (swarf), generated during casing milling operations, out of the hole. The results of the experiments and subsequent analyses are presented in the paper.

The paper describes the equipment and procedures used in the experiments. It also presents the results of the experiments and subsequent analysis relating to the transport efficiency of a range of milling fluids used by MNSL. These experiments were conducted under static and dynamic conditions using a recently constructed settling column and the cuttings transport borehole simulator at Heriot-Watt University. The experiments demonstrate the impact of the rheological properties of the fluid, and the shape and surface area of swarf on transport efficiency. The paper concludes with recommendations on the formulation of fluids for milling operations of this type.
Well Test Interpretation in a Heterogeneous Braided Fluvial Reservoir
Authors: Toro-Rivera M. L. E. , Corbett P. W. M. , Stewart George
Published: December 2007

Braided fluvial reservoirs are important reservoirs around the world and being high net: gross, are often considered to be massive and relatively easy to characterise. This study shows that this is not always the case. Two wells in the offshore part of the fluvial Triassic Sherwood Sandstone reservoir in the Wytch Farm Field, Southern UK, have very similar permeability distributions with arithmetic average permeabilities of 400 and 625md, respectively. The effective permeabilities exhibit a similar and typical degree of heterogeneity in this fluvial reservoir in terms of core permeability. However, their well test effective permeabilities are radically different (44 and 1024md).

A full well test analysis is performed for each well, deriving all possible models that can be interpreted from the pressure derivative. The well testing software used (PanSystem™) allows filtration and resampling of the pressure data and the interpretation of the pressure derivative curve and identification of early, middle and late time flow regions. The models interpreted from the well test analysis are integrated with flow unit models derived from the core permeability, core sedimentology logs and knowledge of the reservoir geology. The flow unit interpretation can be directly related to the well test results. The spatial distribution of the permeabilities is different in the wells and this explains why the probability distribution functions alone fail to discriminate between the wells.

This work addresses the challenge of estimating effective permeabilities in high net:gross braided stream reservoirs. Permeability in this particular field varies by seven orders of magnitude and there is high grain size derived variability at the core plug scale. Interpretation of the well test in such environments can be greatly helped by an improved petrophysical description (probe permeameter), careful screening and averaging of the core data and identifying the flow units (which may differ from conventional net pay). In addition, we observe that the occurrence of negative skin in such environments can be attributed to natural simulation due to sedimentological features. We point out that the running of a production log (PLT) during the testing will greatly reduce the uncertainty in flowing interval and the test-derived parameters.

This work shows that the integrated interpretation of well test pressure data in a geologically-coherent fashion can enable the flow characteristics of the reservoir to be determined at the appraisal stage. This knowledge can then be incorporated in the model of the reservoir for improved performance prediction.
Rate-Dependent Skin From Afterflow
Authors: Lingen P. L.
Published: December 2007

During the afterflow of a pressure build up in a gas well test a unique pressure response is created by the declining rate dependent skin. This paper describes a method to include the effect of the declining rate dependent skin in the response of analytical well models. This results not only in an improved analysis by regression, but also in the possibility to obtain the rate dependent skin from the afterflow response of a single rate gas well test with build up. The accuracy of the resulting rate dependent ~kin values has been validated in some ten multi-rate test analyses.
IOR Potential with Updip Water Injection in the Statfjord Fm at the Statfjord Field
Authors: Hegro Einar , Dalen Vilgeir , Strandenaes H. O.
Published: December 2007

An element model was used to investigate the effect of using the existing crestal gas injectors in the Statfjord Fm at the Statfjord Field for additional updip water injection. The element was extracted from a history matched full field model and refined. The simulations gave accelerated production and increased oil recovery of approximately 5% with updip water injection, primarily because of better pressure maintenance, better sweep of lower parts of the formation and less problems with gas production constraints. Sensitivities on selected parameters did not indicate anything in disfavour of updip water injection. Full field simulations have confirmed the potential of updip water injection, and the scheme is found to fit very well into the overall Statfjord Field strategy.
Productivity of Multifractured Horizontal Wells
Authors: Hegre T. M. , Larsen Leif
Published: December 2007

Accurate methods are presented to determine the productivity of multifractured horizontal wells with transverse or longitudinal fractures. Charts combined with a simple expression give the relationship between the effective wellbore radius and fracture conductivity, fracture size, wellbore radius, number of fractures and distance between the fractures as dimensionless parameters.

The effectiveness of multifractured horizontal wells is illustrated by a variety of examples, with well response compared to non-fractured vertical and horizontal wells and to fractured vertical wells. It was identified that stimulating horizontal wells is favourable in thick formations and in reservoirs with low vertical to horizontal permeability ratio. In particular, it is shown that the potential productivity of horizontal wells stimulated by transverse fractures is higher than for wells stimulated by longitudinal fractures. However, a low fracture conductivity has a much more adverse effect on transverse fractures compared longitudinal fractures. The importance of the number of fractures and especially the distance between the fractures also is demonstrated. Some existing analytical solutions are also discussed and comparisons are made with results from this paper.
Parametric Study of Gas-Condensate Reservoir Behavior During Depletion: A Guide for Development Planning
Authors: Bourbiaux B. J.
Published: December 2007

The results of systematic compositional simulations of gas- condensate depletion in a radial and cross-sectional reservoir model are presented. The effects on productivity, recoveries and fluid distribution are analyzed and quantified when changing various parameters, such as the role of non-Darcy flow, the permeability, the relative permeabilities (kr) in relation with the interfacial tension (IFT), the nature of the fluid.

Below the dew point pressure, the drop in gas productivity is linked to the development of a condensate ring around the wellbore. Gas and condensate kr and their dependence on IFT control the time or pressure at which condensate buildup becomes significant and gas productivity drops. Tight reservoirs with lean gas-condensates may pose early and drastic productivity problems. Far from wellbore, condensate may segregate under the low-IFT conditions met during depletion, especially if the reservoir permeability is high ana the fluid is rich. In a depletion process, condensate recovery is all the lower as the condensate content of the fluid is higher.

The results of this study can be used as a guide during the development planning of a gas-condensate field (1) to estimate the quantitative role played by key rock-fluid parameters during future exploitation, (2) to define the most relevant corefluid measurements and simulation studies for reducing uncertainties on field performance predictions.
Improving Profitability of Gas and Oilfield Operations by Applying New Technologies
Authors: Hartmann Ulrich , Muessig Siegfried
Published: December 2007

Gas fields at an advanced stage of depletion require measures to overcome the back pressure of the gas transmission system and thus maintain production rates. This paper describes measures for cutting costs by applying either conventional or new technologies such as on-site conversion of natural gas into electrical power by combined-cycle processes or fuel cells.
A Fitted for Purpose Slim-Hole Rig
Authors: Sagot André , Dupuis Dominique
Published: December 2007

After testing new slim hole drill strings that are able to perform destructive drilling and wireline coring with positive drilling achievement and positive geological data acquisition, the construction of a purpose built rig for slim hole drilling has been undertaken. It is believed that a purpose built rig will lead to substantial drilling cost breakthroughs and greatly reduce the environmental impact of the drilling operation.

Reducing the Drilling Cost

Environmental protection

Slim Hole Prilling Practices

Slim hole drilling requires a refined control and measurement of all drilling parameters. To achieve this, we need:

Slim hole drilling requires a new rrange of flow parameters versus conventional practices. An original solution has been developed and is presented in this paper.

Based on the above criteria the paper will detail the solutions that provide the foundations adopted to build the slim hole purpose built rig. The rig has begun operations in France in April 1994. The initial results will be available.
Underbalanced Drilling with Coiled Tubing and Well Productivity
Authors: Leising L. J. , Rike E. A.
Published: December 2007

Horizontal wells have shown such gains in productivity in many applications that the damage associated with longtime exposure to drilling fluid was, in many cases, accepted. In addition, the dif-ficulty of removing formation damage in a horizontal well has compounded the problem. With many horizontal wells now being left in an openhole status, formation damage becomes even more important.

Coiled tubing (CT) drilling has grown from four jobs in 1991 to over 120 (estimated) jobs in 1994. The primary motivations for this growth have been: The ability of CT drilling to finish drilling a well in soft forma-tions faster than a rotary rig, andSafe, rigless underbalanced drilling to greatly reduce forma-tion damage in horizontal wells.

This paper reviews the causes of formation damage, both from fluid/solids invasion and stimulation techniques to remove dam-age.

An analytical model is used to estimate the productivity index (PI) for various horizontal and vertical permeabilities, well lengths, and reservoir thicknesses for comparison with results from several case studies.

Options for underbalanced drilling including fluid selection, gas lift, and seal technology are discussed. Candidate selection cri-teria for those evaluating the possibility of underbalanced hori-zontal drilling are presented.
Well Tractors for Highly Deviated and Horizontal Wells
Authors: Hallundbæk Jørgen
Published: December 2007

This paper introduces the oil industry to a new type of downhole tools - the Well Tractors with modular power source designed for running in open hole and inside the completions of horizontal and highly deviated wells.

The Well Tractors are used for cleaning, setting and pulling of plugs, operating sliding sleeves, open hole logging, running of production logs, drilling, perforation guns, cement bond logs etc.

Horizontally the Well Tractors pull coiled tubing and/or wireline beyond 10,000 ft. The Well Tractors are capable of pulling more then 25,000 ft of coiled tubing and/or wireline into a highly deviated well. Furthermore the tools are designed for pushing other tools into the hole, e.g. logging tools, video cameras etc.

The Well Tractors with modular power source are designed in two versions:

A fluid driven version for coiled tubing operations. Powered by brine, water, mud etc. which is pumped down through standard coiled tubing. The tool is controlled from the surface via a wireline running inside the tubing. Through the wireline measurements can be transmitted to the surface. Alternatively the tool can also operate without the wireline which enables it to run with a smaller size of coiled tubing or have a higher flow rate for e.g. cleaning jobs.

An electric driven version of the Well Tractor for wireline operations. Powered and controlled through the wireline.

The Well Tractors are designed in 3 different sizes. A Tractor with an outside diameter of 3 1/8". A Tractor with an outside diameter of 4 3/4" and a Tractor with an outside diameter of 2 1/8".
Integrating Field Measurements With Conceptual Models to Produce a Detailed 3D Geological Model
Authors: Freulon X. C. , Dunderdale I. D.
Published: December 2007

A three dimensional geological model of a reservoir defines the matrix heterogeneities and the petrophysical properties (porosity, permeabilities, saturations). To construct a model two sources of information are used: a conceptual model and the available measured data (subsurface and outcrop) interpolating techniques are needed. To integrate these two perspectives. In this paper two stochastic techniques are compared: the Gaussian model and the Boolean model. The integration of different types of knowledge is a crucial and innovative domain in 3D stochastic modelling and requires contact between petroleum geoscientists and engineers involved in reservoir management.
The Leman Field: Hunting for the Remaining Gas
Authors: Mijnssen F. C. J. , Maskall R. C.
Published: December 2007

The Leman Field is the largest discovered gas field in the southern North Sea. Production is from Rotliegend Sandstones which predominantly have an aeolian origin. In the Shell/Esso acreage the flanks of the Leman Reservoir are sparsely drilled, and potentially large amounts of gas remain in place. In these areas only the relatively poor quality uppermost part of the Rotliegend Reservoir is above the gas/water-contact. Analysing reservoir properties in the uppermost Rotliegend indicates that the variation in reservoir properties within a lithofacies is significantly larger than the variation in average reservoir properties between lithofacies. Sedimentary structures are the most likely cause for this internal heterogeneity. Consequently, drilling a well parallel to the main foreset dip, the direction of maximum heterogeneity, should maximise productivity. In the Leman Field this means that wells should be drilled parallel to the main paleowind direction, which is from southeast to northwest.
Multiphase Rotodynarnic Pumps Extend their Operating Capabilities
Authors: Falcimaigne J. , Durando P. , Loupias M. , Vilagines R.
Published: December 2007

The paper describes the main features of the P302 multiphase pump and presents some results of bench tests carried out to check its hydraulic performances. The P302 is a rotodynamic helico- axial pump based on the Poseidon pumping technology. It is equipped with water lubricated bearings and driven by a high speed electrical motor. The pump was designed to work with a suction pressure much lower than the P300 prototype and to deliver a higher compression ratio. It has fifteen stages of compression cells, in three different series.

Before installing the pump on an onshore production site for endurance tests with actual field fluids, the steady-state behaviour and the transient responses of the pump were characterised on the IFP multiphase loop at Solaize (France). The pump was tested both with single phase fluids (liquid or gas) and a diphasic mixture (fuel-oil and nitrogen) at various GVF and suction pressures. In the paper, theoretical predictions are compared to measured data.

The good results of these tests confirmed the soundness and versatility of the Poseidon hydraulics and also the calculation model ability to predict accurately the performances of rotodynamic pump over a wide range of operating conditions.
Re-Use Rather Than Abandon Offshore Facilities
Authors: Broad T. A.
Published: December 2007

The technology to remove offshore facilities without dismantling them offshore is cost efficient. It also enables a platform topside to be re-used at another location for a significantly lower cost and with an earlier first oil date than that possible by building a new platform. Safety of personnel and security of the environment can be maintained throughout the removal, refurbishment and re-installation operations.
Cost-Effective Field Development Planning and Risk Assessment
Authors: Lane Ian , Early R. K. , Holtslag R. J.
Published: December 2007

This paper will discuss the concept and application of risk management in the North Sea, a mature oil province which now presents increasingly high cost, marginal development prospects. Examples of an integrated approach to risk assessment in field development planning, involving both petroleum and well engineering disciplines, will be examined using case histories from both mature fields and new projects. The use of leading edge technologies in this process will be discussed, in the context of introducing risk and the quantification of possible upsides and downsides in the process of optimising the overall economic return of a project.
Qualification of an HP/HT Retrievable Production Packer
Authors: Fennell Bob , Avignon Bernard , Henderson W. D.
Published: December 2007

Well completion of future HP/HT fields are posing great financial and technological challenges to operators and service companies alike. Field proven equipment already exists to develop such fields but financial and system optimisation is now the driving force behind technological advances. This optimisation drive linked to the overriding HP/HT completion philosophy of keeping completion procedures simple and efficient indicated the requirement of a hydraulic set, retrievable production packer.

This paper looks at HP/HT completion design concepts and equipment qualification concentrating on new technologies being developed and qualified for the production packer. The process of identifying the requirement through to full scale prototype qualification is described.
Bull Heading To Kill Live Gas Wells
Authors: Oudeman Pieter , ter Avest Dick , Grodal E. O. , Asheim H. A. , Meissner R. J. H.
Published: December 2007

To kill a live closed-in gas well by bull heading down the tubing, the selected pump rate should be high enough to ensure efficient displacement of the gas into the formation (i.e. to avoid the kill fluid bypassing the gas). On the other hand, the pressures that develop during bull heading at high rate must not exceed wellhead pressure rating, tubing or casing burst pressures or the formation breakdown gradient, since this will lead, at best, to a very inefficient kill job. Given these constraints, the optimum kill rate, required hydraulic horsepower, density and type of kill fluids have to be selected. For this purpose a numerical simulator has been developed, which predicts the sequence of events during bull heading. Pressures and flow rates in the well during the kill job are calculated, taking into account slip between the gas and kill fluid, hydrostatic and friction pressure drop, wellbore gas compression and leak-off to the formation. Comparison with the results of a dedicated field test demonstrates that these parameters can be estimated accurately. Example calculations will be presented to show how the simulator can be used to identify an optimum kill scenario.
Reliability Analysis on PVT Correlations
Authors: De Ghetto Giambattista , Paone Francesco , Villa Marco
Published: December 2007

This paper evaluates the reliability of the most common empirical correlations used for determining reservoir fluid properties whenever laboratory PVT data are not available: bubblepoint pressure, solution GOR, bubblepoint OF W, isothermal compressibility, dead-oil viscosity, gas-saturated oil viscosity and undersaturated oil viscosity.

The reliability of the correlations has been evaluated against a set of 195 crude oil samples collected from the Mediterranean Basin, Africa, the Persian Gulf and the North Sea. About 3700 measured data points have been collected and investigated. All measured data points are reported in the paper. For all the correlations, the following statistical parameters have been calculated: a) relative deviation between estimated and experimental values, b) average absolute percent error, c) standard deviation.

Oil samples have been divided into the following four different API gravity classes: extra-heavy oils for °API< 10, heavy oils for 10<°API≤ 22.3, medium oils for 22.3<°API< 31.1, light oils for °API> 31.1.

The best correlations both for each class and for the whole range of API gravity have been evaluated for each oil-property.

The functional forms of the correlations that gave the best results for each oil property have been used for finding a better coiTelation with average errors reduced by 5-10%. In particular, for extra-heavy oils, since no correlations are available in literature (except for viscosity), a special investigation has been performed and new equations are proposed.
J-Block Template Drilling: Innovation and Teamwork Break Cost and Time Barriers
Authors: Henderson K. W.
Published: December 2007

Phillips Petroleum Co. U.K. Ltd (Phillips) commenced template drilling on the Judy and Joanne field development in Block 30/7a (J-block) in May 1993. Since that time progress has been remarkable. Following the setting of a 65 Tonne, 12 slot, drilling template by a 4th Generation Universe Class jackup, two 70" holes were drilled for docking pile installation. The 120 ft long, 60.5'' diameter, 100 tonne piles were picked up from a vessel using the rig draw-works and run and cemented using standard oilfield equipment. It is believed that this is the first time such an operation has been carried out from a jackup drilling rig. Batch setting of 7 tapered and 2 conventional conductor strings through 9 template slots was completed inside 12 days. The optimal and unique well design then allowed drilling to proceed at record rates, including a world record of 8,263 ft of 12-1/4" hole in one 24 hr period being achieved.

This paper discusses the innovative engineering, design, cost reduction and teamwork philosophy that has seen the project progress ahead of schedule and significantly under budget.
Experience in the Detection and Suppression of Torsional Vibration From Mud Logging Data
Authors: Fear M. J. , Abbassian Fereidoun
Published: December 2007

Vibration detection from mud logging systems has revealed that torsional vibration is common in harsh drilling environments, and is a major cause of bit and drillstring failures. Suppressing this type of vibration with an automated vibration detection system, torque feedback, and rigsite vibration suppression guidelines has produced a significant improvement in drilling performance.
Application of QRA Methods to Casing Seat Selection
Authors: Parfitt S. H. L. , Thorogood J. L.
Published: December 2007

There are diverse approaches to casing setting depth determination via kick tolerance, which are inconsistent with each other and involve apparently arbitrary design values. This paper presents a risk based approach to setting depth selection during design which explicity considers the variables contributing to influx volume and their uncertainties. The use of a risk based approach provides a unifying theme across a range of hole sizes and operational variables allowing comparisons of options where none was possible using previous design approaches.
Post-Frac Productivity Calculation for Complex Reservoir/Fracture Geometry
Authors: Bale Arthur , Smith M. B. , Settari Antonin
Published: December 2007

This paper presents a simple, practical approach to calculating postfrac productivity for indirect vertical fracture completion (IVFC) wells. The case envisioned is one where the main pay is not adjacent to perforations; with wellbore-to-pay communication being created via a wide propped vertical fracture. Such a fracture generally involves tip screenout type treatment designs, though that is not a subject of this paper.

Previous publications1,2 presented a case history of limiting perforations in a well to competent, lower permeability rock, and creating a propped fracture to communicate with weaker, higher permeability pay. An IVFC well in this formation served two goals: 1) to avoid need for gravel packing or other sand control measures required when the main pay is perforated, and 2) to maximize production from lower permeability pay sections, thus delaying water breakthrough (WBT) and increasing total reserve recovery. As part of that case history, a brief calculation scheme was proposed for predicting post-frac PI.

This paper discusses details of this calculation procedure, which is presented in a more general (partly dimension- less) form. Examples of predicted PI using these calculations are presented for several field cases where complex fracture completions of this type are being considered and implemented. In addition, accuracy of the simple, analytical calculations are tested against 3-D reservoir modeling. Results of the numerical modeling generally verify the simple procedure, but also place some limits on where / when analytical calculations should be used. The 3-D model is then used to consider possible impacts of turbulent flow and other parameters not included in the analytical calculation. Turbulent flow in the fracture was found to be a significant factor, even for single phase flow of oil.

Finally, predicted PI is compared to field measured post- frac results for several cases. Many field cases show unmistakable indications of turbulent flow, making it clear this factor must be considered in design of such completions.
Geotechnical Integration and its Impact on Field Management. The IRMA Methodology.
Authors: Riddiford F. A. , Goupillot M.
Published: December 2007

The ability to accurately model sub-surface reservoir detail and those features which are likely to control and influence the displacement processes associated with hydrocarbon production, is essential if we are to improve our ability to predict field performance. This paper outlines a methodology for fully integrating data into a comprehensive description of the sub-surface, which can be rapidly updated as new data become available, and the processes of Upscaling and Downscaling undertaken in moving between these detailed geological models and the simulation environment. The benefits of using 3D seismic data to improve our understanding of the sub-surface, are discussed.

The process of data integration utilising an insight gained from both static as well as dynamic data is used to develop 3D numerical models of the sub-surface. Static data comprising acoustic impedance 3D blocks extracted from well and seismic, combined with petrophysical models calibrated using core and log data, constrain geostatistical models developed at the sand body scale. Object models and fault and fracture information developed from core and seismic data are also combined to give unified static geological models at the stratigraphic scale, which are consistent with all the known data. The impact of dynamic disturbance from evaluation of well test and RFT data are similarly used to constrain the plausibility of the geological models being built.

Upscaling of the detailed geological models provides data sets of a size consistent with running reservoir simulation models. Downscaling to address history match issues and reservoir monitoring including 4D seismic, ensures that reference is always made back to the current geological model, this the vehicle through which all change is invoked.

Field examples are used to demonstrate the benefits and the interactive and iterative nature of this innovative methodology, which combines existing and newly developed techniques from exploration and production to develop geological and equivalent simulation models, which are fully consistent across the sub-surface disciplines.
Historical Performance of Gas Injection of Ekofisk
Authors: Jakobsson N. M. , Christian T. M.
Published: December 2007

Hydrocarbon gas has been injected into the Ekofisk field for almost twenty years. Gas injection has always been for operational reasons. This case history reviews the historical performance and benefits of the gas injection. Gas migration, gas distribution and mechanisms involved when gas is injected into a naturally fractured chalk reservoir are discussed. The findings are based on field and laboratory data. The benefits are estimated by means of reservoir modelling.

The Ekofisk field is a naturally fractured chalk reservoir with low matrix permeability. The natural fracturing enhances overall permeability and has made commercial production possible. Since gas injection commenced in 1975, a total of 1.2 TSCF of gas has been injected. All the gas has been injected into the crest of the field.

This paper demonstrates that the natural fracture system at Ekofisk represents a medium for the injected gas to contact and mix with the reservoir fluids and that major fault systems are important factors for gas migration and gas distribution. There is no clear oil production response to gas injection. The production response that can be observed is generally limited to elevated GOR. Gas injection still appears to have benefitted oil recovery. Reservoir modelling suggests that gas injection will increase oil recovery by 2 to 3 percent of original oil in place. Historical benefits are, in addition to pressure support, swelling of the oil and vaporization/stripping of lighter hydrocarbons.
Surfactant Design Criteria for Successful Carbon Dioxide Foam in Sandstone Reservoirs
Authors: Kuhlman M. I. , Lau H. C. , Falls A. H.
Published: December 2007

Laboratory results demonstrate that surfactant adsorption on sandstones is minimized and foam performance improved by reducing the ethoxylate chain length in alcohol ethoxy sulfonates and blending unethoxylated and ethoxylated sulfonates to optimize desirable properties. These properties include increased mobility reduction, more gas-oil foam formation, and enhanced surfactant transport in the oil and water, which all appear to be negatively affected by the presence of long ethoxylate chains in a surfactant.

A series of experiments are used to show that laboratory adsorption measurements can only be extrapolated to reservoirs by 1) replicating the anaerobic conditions of reservoirs, 2) matching the reservoir pH in a CO2 flood and 3) differentiating authogenic minerals from drilling mud found in reservoir cores.
Thermal Stability of Sulfonated Polymers
Authors: Audibert A. , Argillier J-F.
Published: December 2007

Polyacrylamides which are used in oil applications i.e. polymer flooding and water based muds, are hydrolysed versus time and temperature. This leads to a lack of tolerance towards electrolyte contamination and to a rapid degradation inducing a loss of their properties. Modifications of polyacrylamide structure have been proposed to postpone their thermal stability to higher temperatures. Monomers such as acrylamido methylpropane sulfonate (AMPS) or sulfonated styrene/maleic anhydride can be used to prevent acrylamide comonomer from hydrolysis. The aim of this work is to study under controlled conditions, i.e. anaerobic atmosphere, neutral pH, the stability of sulfonated polymers in order to distinguish between hydrolysis and radical degradation reactions.

It has been observed that up to 100°C, the AMPS group is stable and protects the acrylamide function from hydrolysis up to 80%. At higher temperature, even the hydrolysis of the AMPS group occurs, giving acrylate and β, β dimethyl taurine, with a kinetics that depends on temperature and time. Degradation in terms of molecular weight then occurs indicating that it follows a radical decarboxylation reaction. It can be limited either by the use of free radical scavenger or when the polymer is in the presence of a mineral phase such as bentonite.

These results provide valuable data for the determination of the limits of use of sulfonated copolymers and guidelines for optimizing chemical structure of sulfonated polymers used in water based formulation, in particular to enhance their thermal stability.
Solids Precipitation in Reservoirs Due to Nonisothermal Injections
Authors: Deo M. D. , Kumar Rajinder
Published: December 2007

In most nonthermal injection processes, fluids are injected at temperatures much lower than reservoir temperatures. Even though injected fluids are heated due to the prevailing geothermal gradient, in most applications, they reach the formation at temperatures far lower than the reservoir temperatures and cool the formation in the vicinity of the wellbore. The temperature lowering could cause solids precipitation particularly for paraffinic crudes and for oils susceptible to asphaltene precipitation. In this paper, the effect of cold-water injection in paraffinic crude reservoirs has been studied.

Temperatures of water reaching the formation were calculated using an analytical wellbore model modified to include realistic wellbore resistances. These temperatures were observed to be below the cloud points of paraffinic crudes. Solid-liquid equilibrium calculations showed that there was a strong possibility of paraffin precipitation under certain injection conditions. The effect of precipitation on oil recovery was analyzed using the method of characteristics approach. The calculations showed the extent of reduction in oil recovery due to paraffin precipitation near the wellbore.
Correlations for predicting Viscosity of W/O-Emulsions based on North Sea Crude Oils
Authors: Rønningsen Hans Petter
Published: December 2007

This paper describes some simple correlations which can be used to obtain reasonable estimates of relative viscosities and viscosities of water-in-crude oil emulsions.

The apparent viscosities of water-in-crude oil emulsions based on eight different North Sea crude oils of different types have been fitted to a general empirical equation which provides estimates of relative viscosities at temperatures between 5 and 40°C, water cuts between 10 and 60% and shear rates between 30 and 500 s‒1. The estimates are in general within 15-30% of experimental values. A correlation between crude oil viscosity and average molecular weight, can be utilized to obtain estimates of emulsion viscosities above about 20 °C, when only the molecular weight of the crude is known.

The yielding (or restart) behaviour of some of the emulsions at low temperature (5 °C) is described in terms of static yield stress as a function of water volume fraction.
Formation Damage by Fines Migration Including Effects of Filter Cake, Pore Compressibility, and Non-Darcy Flow—A Modeling Approach to Scaling From Core to Field
Authors: Liu Xinghui , Civan Faruk
Published: December 2007

The transport of fine particles in formations has been recognized as the major cause of formation damage. In this study, a two-phase, multi-species formation damage model was developed. The model allows for filter cake formation on the sand face, particle mobilization and retention in pore spaces, particle transfer at fluid-fluid interface, and porosity and permeability alteration. The effects of non-Darcy flow, relative permeabilities, capillary pressure, and wettability of fine particles and pore surfaces on two-phase flow formation damage were considered. A one-dimensional numerical simulator was constructed based on the model.

The model was validated using published laboratory data. Parameters involving the formation damage model were also determined using the laboratory data. With respect to field applications, the extent and degree of formation damage around the wellbore and the associated skin factor were predicted by implementing the model in radial flow. This study serves to enhance the understanding of formation damage due to particulate processes. This model is a useful tool for analyzing formation damage in laboratory core tests and simulate and predict formation damage in field operations.
Controlled-Release Scale Inhibitor for Use in Fracturing Treatments
Authors: Powell R. J. , Gdanski R. D. , McCabe M. A. , Buster D. C.
Published: December 2007

This paper describes results of laboratory and field testing of a solid, controlled-release scale inhibitor for use in fracturing treatments. Laboratory testing with a continuous flow apparatus has yielded inhibitor release rates under dynamic conditions. The inhibitor was tested to determine the minimum inhibitor concentration required to inhibit the formation of CaCO3, CaSO4, and BaSO4 scales in a brine. A model to predict the long-term release rate of the inhibitor was developed from data collected on the continuous flow apparatus. Data from treated wells will be compared with predictions of the model.

Inhibitor release-rate testing in a continuous-flow apparatus shows that a solid, calcium-magnesium polyphosphate inhibitor has a sustained release profile. Release-rate testing shows that the inhibitor can be used up to 175°F. The inhibitor is compatible with both borate and zirconium crosslinked fracturing fluids and foamed fluids.

The effective lifetime of the scale treatment can be predicted based on a model developed from laboratory data. The input variables required for the prediction include temperaturewater productionamount of inhibitorminimum effective concentration of inhibitor for the specific brine

The model can be used to aid in the design of the scale inhibitor treatment.
A High-Resolution, Fully Implicit Method for Enhanced Oil Recovery Simulation
Authors: Liu J. , Pope G. A. , Sepehrnoori K.
Published: December 2007

A high-resolution total-variation-diminishing (TVD) finite-difference scheme has been developed and used in our multidimensional multicomponent, multiphase, finite-difference, IMPES-type compositional simulators for years. A variety of simulation results of enhanced oil recovery (EOR) processes have shown that this scheme gives convergent, high-order, accurate solutions. However, a restriction on the timestep size is always needed to ensure stability because of the IMPES formulation. This restriction sometimes can be very severe which means in some cases simulations are of high cost or even infeasible. It is well known that the fully implicit formulation is the most stable method. The standard approach, however, usually adopts lower-order finite-difference schemes for both the temporal and spatial discretizations because of computational requirements and difficulties in the program coding and the implementation of the physical property models. The advantage of the methods thus are overshadowed by the increased amount of numerical dispersion associated with large truncation error, which is especially detrimental to accurate field simulation and process design. A new fully implicit, high-resolution algorithm and a simulator based on the algorithm were developed and are described in this paper. The algorithm is second-order correct in time and uses a third-order finite-difference method to discretize the first-order spatial derivatives and a new total-variation-diminishing (TVD) third-order flux limiter to constrain the gradients of the fluxes to obtain accurate, oscillation-free solutions. All variables and TVD limiter functions are evaluated using the values of the new timestep. The schemes are applied for computing both the interface concentrations and mobilities with flow directions either in or against the coordinate directions and for nonuniform grids. The Jacobian matrix and the residual equations are updated at the end of each iteration. Unlike many numerical schemes in the literature, there are no problems with generalizations of this scheme.

The new algorithm and the simulator are verified by the good agreement between numerical results and analytical solutions. Verification cases with analytical solutions were also used to compare different simulation approaches. The new algorithm has higher resolution than standard methods, is more stable than the IMPES method, and stability is preserved with nonuniform grids.
A Computationally Efficient Gauss-Newton Method for Automatic History Matching
Authors: Tan T. B.
Published: December 2007

Methods for automatic history matching that have been previously published have either required excessive computational time or had linear convergence characteristics. This paper presents a modified nonlinear regression method, the Gauss-Newton method, that has quadratic convergence properties and yet is extremely computational efficient. The modifications to the method are described in full detail. The method has been implemented in a three-dimensional three-phase simulator.

The simulator was applied to a case study using the Seventh SPE Comparative Problem. It was shown to be capable of estimating multiple parameters such as permeability and porosity. Selected matches from actual wells in a field study were also presented. The results of an actual well test were also matched. It was demonstrated that the automatic history matching simulator could identify the reservoir parameters that had significant effect on the observed data.
Dual-Porosity Simulation Incorporating Reinfiltration and Capillary Continuity Concepts Part I: Single Gridcell
Authors: Tan J. C. T. , Firoozabadi Abbas
Published: December 2007

We have developed a method to account for reinfiltration and capillary continuity effects in the simulation of fractured reservoirs, The proposed method requires fine grid simulation of a three-block stack (two-block stack if it is assumed that there is no capillary continuity). The information is then used to construct the drainage curves of different gridcells that may contain a large number of matrix blocks. Variation of capillary pressure, block height, and permeability of various matrix blocks within a gridcell are accounted for without the need for fine grid simulation.
Evaluating Miscible and Immiscible Gas Injection in the Safah Field, Oman
Authors: Hearn Charles L. , Whitson Curtis H.
Published: December 2007

The reservoir modeling approach presented in this paper illustrates how available engineering tools can be used to evaluate the technical feasibility and economics of high-pressure gas injection. The key components to such a study included: 1) equation of state (EOS) modeling of experimental PVT data, matching miscible and immiscible slim tube results, and systematically reducing the number of components used in the EOS model to minimize computational requirements, 2) studying numerical grid effects, displacement mechanisms, optimal well pattern, and injection pressure with 2D cross-section and 3D sector models, and 3) comparing compositional results with simulations based on the black-oil PVT formulation used in full-field history matching and reservoir management modeling.
Estimating Two and Three Dimensional Pseudo-Relative Permeabilities With Non-Linear Regression
Authors: Tan T. B.
Published: December 2007

Pseudo-relative permeabilities are usually generated to match fine grid models of typical cross-sections of the reservoir with coarse grid models and these are then used in full field models to reduce the number of cells. Various analytical formulae have been proposed to calculate these pseudos. In practice, the analytic formulae merely represent an educated first guess of the pseudo-relative permeabilities necessary to match the fine grid model. When used in the coarse grid equivalent of the fine grid model, these pseudo-relative permeability curves often require further trial and error adjustment in order to match the fine grid model results.

This paper describes an approach whereby these pseudos may be easily generated with non-linear regression analysis (automatic history matching). The relative permeability values of the saturation function tables are allowed to vary independently until a match of the observed saturations and production rates of the fine grid model is obtained with the coarse grid model. Calculated pseudo-functions are presented for a difficult previously published problem with non-communicating layers. A case study shows the sensitivity of the pseudos to coarse grid definition and production rates. Previously published formulae have been restricted to two-dimensional vertical cross-section pseudos. As a result, areal heterogeneity and sweep displacement efficiency have been ignored. In this paper, we extend the pseudo concept to three dimensions by generating a single pseudo-relative permeability curve to represent a fine three-dimensional model with a coarse three-dimensional model.