bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Study of High-Temperature Foam for Acid Diversion
Authors: Kam S. I. , Frenier W. W. , Davies S. N. , Rossen W. R.
Published: December 2007

Foam treatments are used worldwide for acid diversion in matrix acid well stimulation. Many field treatments require foam effectiveness at elevated temperature in the presence of both acid and corrosion inhibitor.

This study examines four surfactant formulations at room temperature, 220° and 400°F, with and without acid and corrosion inhibitor. The surfactants included amphoteric as well as nonionic foaming agents. The acid formulation was a mixture of chelating agent and HCl, with pH about 4. Formulations were tested at all three temperatures for foaming with N2 gas (80% quality) at back-pressure of 600 psi in sandpacks and for bulk-foam stability in a pressure cell.

Foam was created in most cases at 75°F without acid or corrosion inhibitor. Creating foam with acid and corrosion inhibitor at 400°F was more difficult, requiring high injection rates and lower foam quality. Once formed, strong foam had higher mobility at elevated temperatures than at room temperature. Addition of corrosion inhibitor was more adverse to foaming than acid itself. At 400°F foam propagation was slower, and steady-state pressure gradient was lower, than at 75°F. The two steady-state strong-foam regimes reported elsewhere were present at 220ºF and in the presence of acid. Pressure gradient at 220°F was lower in both the high-quality and low-quality foam regimes.

The bulk-foam stability results agree qualitatively with the sandpack results, but quantitative relationships between the two tests are hard to draw. These results also suggest that these surfactants degrade over a period of hours at 400°F but not at 220º. Residence time in the heated sandpack therefore may have been too short to fully represent field application at 400°F.

These results are consistent with decreasing foam stability at higher temperature; adverse interactions between foaming surfactant and inhibitor; easier foam generation and propagation at higher velocity and lower foam quality; and greater difficulty in creating foam under conditions that reduce steady-state foam strength.

These results can aid design of high-temperature foam-acid diversion treatments.
Gas Assisted Acidizing of Carbonate Formations
Authors: Shukla S. , Zhu D. , Hill A. D.
Published: December 2007

Matrix acidizing is a commonly used well stimulation technique in which acid is injected into the formation in order to dissolve a portion of the rock and hence, recover or enhance the permeability in the near well-bore region. In carbonates, when acid is injected, selective dissolution of the rock takes place creating highly permeable flow channels, called wormholes. In general, for a matrix acidizing treatment in carbonates, the deeper the wormholes penetrate into the formation, the better the outcome, as characterized by a lower skin factor. Thus, the deeper the wormhole penetration achieved with a given volume of acid, the more efficient the treatment. In this paper, we present laboratory results that show that wormhole propagation is enhanced by injecting nitrogen gas ahead of the acid.

As wormholes are being created, not all of the acid reaches the wormhole tip. A significant part of the acid is lost as fluid loss to adjacent pores. If this fluid loss can be controlled, then more of the acid can reach the wormhole tip, and hence the penetration of wormholes can be more efficient. This paper investigates the effect of saturating the carbonate rock with gas (nitrogen) prior to the injection of acid in order to reduce the permeability to acid, and thus reduce the fluid loss from the main wormhole.

It was found that gas injection prior to acid injection does significantly reduce the volume of acid required to propagate wormholes through cores. This effect is observed both at room temperature and at higher temperatures. The presence of gas in the core reduced the acid volume needed for wormhole propagation through the core by a factor of up to 3. The paper presents an extensive set of experimental results for both gas- and liquid- saturated carbonate cores subsequently treated with strong HCl solutions. We show that the acid volumes are generally smaller for the nitrogen-saturated cores, and that the wormholes created are narrower and less branched than in the case of water saturated rocks. We also show that the presence of oil saturation at residual water saturation in the core has a similar beneficial effect on wormhole propagation to gas injection. On the other hand, oil present at its residual saturation had little effect on the acidizing process. All of these results confirm the strong influence that fluid loss from a propagating wormhole has on the efficiency of the acidizing process in carbonates.
Influence Of Drill-In Fluids Composition On Formation Damage
Authors: SÁnchez Erna , Audibert-hayet Annie , Rousseau Lionel
Published: December 2007

Drill-in fluids are generally water-based muds containing a viscosifier, a fluid loss reducer, salts and sized calcium carbonate particles. Formation damage mechanisms induced by the use of water based mud formulations (WBM) have been extensively studied and correspond to different phenomena such as water trapping, polymer adsorption and retention, and particle plugging. In this paper, a detailed study was carried out on the behaviour of scleroglucan based formulations generally proposed for high temperature zone and/or high permeability reservoirs. In addition, a classical xanthan based mud was prepared and the performances of xanthan and scleroglucan containing formulations were compared. This work covers not only the effect of the fluid composition, including the presence or not of drilled solids but also the filtration conditions such as shear rate and temperature. Filtration curves obtained under static conditions can be related to the rheological behaviour and thermal stability of the biopolymer used as a viscosifier. These curves are not related to the solid content of the mud. Under dynamic conditions, the filtration curve strongly depends on the aggregation tendency of the scleroglucan sample.

Mud filtrates have been characterized by multi angle laser light scattering coupled with size exclusion chromatography (SEC/MALLS). Characterization of the composition of the filtrate as well as the determination of the polymer molecular weight distribution, is very important to understand the formation damage tests performed on high permeability cores under downhole saturation conditions. Also, both the cake permeability and structure obtained by cryo SEM helped to understand the damage mechanisms observed with such formulations.
Optimized Drill-In Fluid Leads to Successful Open Hole Gravel Pack Completion Installation in Unconsolidated Reservoirs – Case History
Authors: Cobianco S. , Pitoni E. , Ricci P. N. , Galli M.
Published: December 2007

In this paper the designing process and the development work involved in the optimization of the drilling and completion fluids and their subsequent successful application in a highly deviated gas well recently completed in the South of Italy is reported. The most suitable fluid for drilling and underreaming operations was identified by an extensive laboratory study on the basis of the reservoir characteristics: temperature, estimated pore pressure gradient, effective permeability and sand control completion type. Two nondamaging fluid formulations were proposed: an environmental friendly formate-CaCO3 system and a conventional calcium chloride-CaCO3 formulation. For both these fluids the most suitable viscosifier, effective fluid loss reducer and appropriate particle size distribution of the bridging solids had been investigated and identified in the laboratory. Coreflooding tests showed similar fluid loss properties and return permeability results for both the formulations, but different trends had been observed during backflow as far as the removal of the filtercake and the lift-off pressure are concerned. Other considerations regarding the use of the expensive heavy formate-based brine in high permeable sands where massive fluid loss can be experienced led the selection of the CaCl2-formulation, even for drilling and completion.

In the field, all drilling and completion phases proceeded as planned and no fluid losses were recorded while drilling, underreaming and gravel packing, confirming the good work carried out in the laboratory. No matrix stimulation treatments were performed for clean up and expected gas rate was soon overcame by the well.
Consideration of Damaged Zone in Tight Gas Reservoir Model with Hydraulically Fractured Well
Authors: Behr Aron , Mtchedlishvili George , Friedel Torsten , Haefner Frieder
Published: December 2007

The paper shows a way to provide a detailed description of conditions in the hydraulically damaged fracture environment after closure and how to integrate it into a reservoir simulation model.

A special model initialization algorithm was developed and realized in a support tool to make possible the computing a post-fracture performance in tight gas formations by a reservoir simulator. The input represents the treatment schedule of the fracturing process and some results produced by commercial fracturing packages or geophysical measurements.

To represent the fracture geometry and properties, the information about the distribution of the proppant concentration in the fracture as well as fracture width variation is translated into the permeabilities and porosities of the fracture gridblocks. To determine the fracturing fluid saturation in the invaded zone, a new approach was derived to imitate the fracture propagation at a fracturing period under consideration of the leakoff processes. The penetration of the fracturing fluid into the matrix was modeled by Buckley-Leverett equations for two-phase non-miscible displacement with boundary conditions provided by a classical leakoff theory.

The approach is illustrated with a simulation model prepared to the analysis of the cleanup process in a damaged fractured well within a Rotliegende tight gas formation in North Germany.
A Decline Curve Analysis Model Based on Fluid Flow Mechanisms
Authors: Li Kewen , Horne Roland N.
Published: December 2007

Decline curve analysis models are frequently used but still have many limitations. Approaches of decline curve analysis used for naturally-fractured reservoirs developed by water flooding have been few. To this end, a decline analysis model derived based on fluid flow mechanisms was proposed and used to analyze the oil production data from naturally-fractured reservoirs developed by water flooding. Relative permeability and capillary pressure were included in this model. The model reveals a linear relationship between the oil production rate and the reciprocal of the oil recovery or the accumulated oil production. We applied the model to the oil production data from different types of reservoirs and found a linear relationship between the production rate and the reciprocal of the oil recovery as foreseen by the model, especially at the late period of production. The values of the maximum oil recovery for the example reservoirs were evaluated using the parameters determined from the linear relationship. The results demonstrated that the analytical decline analysis model is not only suitable for naturally-fractured reservoirs developed by water flooding but also for other types of water drive reservoirs. An analytical oil recovery model was also proposed. The results showed that the analytical model could match the oil production data satisfactorily. We also demonstrated that the frequently-used nonlinear type curves could be transformed to linear relationships in a log-log plot. This may facilitate the production decline analysis.
Casing Vapor Recovery Systems: An Open or Shut Case
Authors: Jones Jeff
Published: December 2007

Several field demonstrations, field experiments, numerical models, physical models and analytical models have been reported in SPE literature and other forums concerning the applicability of Casing Vapor Recovery systems in steam enhanced oil recovery projects. Conclusion of this review is that CVR systems are effective tools in improving performance of steam EOR projects.
Resin Coated Prepacked Sand Control Liner
Authors: Lombard Michael S. , Scott Gregory D. , Swanson Glenn S.
Published: December 2007

A novel and simple sand control technology has been developed and field tested featuring a prepacked liner consisting of thermosetting resin coated sand grains bonded by heat onto a perforated steel base pipe to form a solid, porous, and permeable cylindrical sand liner that can be installed into a wells requiring sand control. The Resin Coated Prepacked Sand Control Liner is a cost effective tool that can be applied to a variety of wellbore situations requiring remedial or primary sand control. The liner does not use wire wrapping and is constructed using standard oil field tubulars and commercially available thermosetting resin coated sand. The liner fills a need in certain sand control situations that cannot be solved using conventional technology. The Resin Coated Prepacked Liner is used with and without secondary gravel packing, depending on the well and reservoir conditions. The Resin Coated Prepacked Liner is currently installed in one well in the Long Beach Field, Southern California as a field test in a problem well that has historically experienced wellbore sand accumulation and repeated pump failures. Since installation in June 2002, the well has been sand free with an unexpected increase in oil production.
Binary Corrosion Inhibitors Offer Improved Corrosion Control
Authors: Zaid Gene H. , Sanders Donald W.
Published: December 2007

An improvement has been made in anti-corrosion chemicals for oilfield use. A binary corrosion inhibitor has been patented and field proven which combines an epoxy resin and an amine curing agent. The proper application of this unique combination of chemicals forms a bond with the oxide film present on downhole metal surfaces. The result is a corrosion inhibitor barrier that is more tenacious than conventional polar filming amines, reducing application frequency and labor costs, and even more importantly, downhole failures. The binary corrosion inhibitor is also an improvement over and is more versatile than other epoxy-amine products.
Discovering The Elusive Source of Water in the Mene Grande Field
Authors: Herring T. , Gomez H. , Oriozabala G. , Masaccese D.
Published: December 2007

The Mene Grande field has been producing since the early 1900s. Water production has been observed since the beginning with a slow steady increase in field water cut, which is currently at 40%. The watercut is repeatedly observed to decrease with increasing oil production and increase with decreasing oil production. This phenomenon can be repeated within a single well multiple times. Another typical production behavior of the Mene Grande Field is a double decline in production rate when plotted on semi-log paper much like a two layer system.

The current study seeks to offer an explanation for this unusual reservoir behavior with a focus on integrating production data, and quality control of the geostatistical model using pressure transient analysis, material balance and variogram analysis. Detailed well models have been used to guide the geostatistical input by history matching selected transient tests including the very characteristic derivative response of this heterogeneous fluvial reservoir. Additional quality control has been obtained by matching variograms from pseudo wells in the inter-well area. These variograms have both highlighted flaws and suggested remedies to the previous modeling methodology.

The overwhelming conclusion is that the dominant source of water production is the depletion of the reservoir shale. This conclusion also provides significant insight into the reservoir characterization and communication levels within the field. The results have had a direct impact on completion strategies and IOR evaluations.

The results of this work demonstrate how the use and combination of traditional analysis can be integrated to enhance the reservoir characterization process. The methodology applied during this work can easily be included in similar reservoir characterization projects.

To our knowledge significant water production and pressure support has not previously been linked to the depletion of reservoir shales within oil reservoirs. It is however felt that this mechanism offers an explanation for many of the Costal Bolivar fields, which tend to have similar water production profiles over the long term.
An Economic Appraisal of Hole Cleaning Using Hydraulic Horsepower and Jet Impact Force
Authors: Wright James , Chukwu Godwin A. , Khataniar Santanu , Patil Shirish
Published: December 2007

One of the effective steps in reducing the operating costs for drilling an oil/gas well is to optimize the energy used at the mud pumps. Mud pumps are massive pieces of equipment and they serve as integral part of the cuttings removal system. A variety of hydraulic optimization designs are available, however, in this study, the efficiency and cost effectiveness of two methods namely; Hydraulic Horse Power and Jet Impact Force are compared. Both of these methods have a fundamental objective of maximizing the available hydraulics to provide optimum hole cleaning.

This paper presents an economic comparative analysis of using the Hydraulic horsepower and the Jet impact force for optimizing hydraulics for hole cleaning. The evaluation and analysis of parasitic pressure losses and the impact on optimization using both methods are presented. By determining the optimum bit nozzle sizes, the horsepower requirements and the energy cost for each method are determined and analyzed.
Rate Forecasting of a Mature Waterflood Using Fractional Flow Theory and Hyperbolic Decline Curve Analysis, East Wilmington Long Beach, California
Authors: Al-Sharif S. , Rael E.
Published: December 2007

THUMS Long Beach Unit has developed and maintained a strong waterflood in the Ranger reservoir. Historically, Log water-oil ratio (WOR) vs. cumulative produced oil (Np) relationships have been used to predict field oil and water rates over time. An assumption made when forecasting by Log WOR vs. Np is that the total liquid rate remains constant over time. This assumption has proved to be inadequate in accurately modeling the performance of the flood with respect to total fluids production. THUMS has experienced an increase in liquids production per day on a well-by-well basis and on a total Ranger base performance level over time. As redevelopment of the waterflood progresses, a more accurate method of predicting total fluids production is required for facility planning, management of future lifting costs, and optimization of reservoir performance.

This document discusses the methodology applied by THUMS Long Beach Unit to forecast oil and water rates over time. The methodology uses a combination of predicting oil rates by hyperbolic curve fitting, and water rates by fractional flow (fw) relationships. Ranger reservoir forecasting consists of subdividing the Ranger into key forecast areas. Once the areas have been defined, a reservoir analysis is performed to determine current saturations for each producing interval, based on hydrocarbon pore volumes injected to date (HPVI). A log WOR vs. Np relationship is established based on the theoretical fractional flow relationship. Using Arps decline variables to hyperbolic best-fit base oil production for the areas yield an Np vs. Time relationship. The Np vs. Time relationship is then applied to the theoretical Log WOR vs. Np curve specific for that forecasting area. The result yields a more reliable water forecast, which honors theoretical and observed inclining water rates over the producing field life.
Analytical Method to Predict Waterflood Performance
Authors: Lerma M. K. Val
Published: December 2007

It’s difficult to predict waterflood performance in heterogeneous, layered reservoirs. Fractional flow analysis provides a fundamental approach to the problem. Each layer can be analyzed and then a composite formed to model the reservoir’s performance. Various data sources can be used to ensure the validity of the analysis. This study incorporated information from the Inglewood Oil Field, including injection profiles, core data, tracer data, log data and production data to model waterflood performance on a layer by layer basis. A production historical match was then made to validate the fractional flow analysis. This information can now be used to calculate the expected production schedule and ultimate oil recovery, and the timing necessary for that recovery from each layer. Finally, this information forms an economic basis for well drilling and workover activities to allow maximum waterflood sweep efficiency.
Cost/Benefits of Horizontal Wells
Authors: Joshi S. D.
Published: December 2007

This is a summary of state of the art horizontal well technology and a review of the economic benefits of horizontal wells. The paper describes various reservoir applications of horizontal wells from primary recovery to EOR applications. The paper includes field examples of different applications.

Although horizontal wells have been drilled as early as 1927, the major thrust of drilling horizontal wells started in 1980. Initial wells were short length wells (about 250 ft. long wells). In 1985, the first medium radius horizontal well was drilled using a down-hole mud motor. Since then, using horizontal wells has become a common practice. Today, the medium radius drilling technique is the most commonly used drilling method.

In the U.S., the majority of applications are in low permeability, naturally fractured, carbonate reservoirs. However, in California, Alaska and Gulf of Mexico most of the wells are drilled in clastic reservoirs. Similarly, outside the U.S., most of the horizontal wells are drilled in clastic reservoirs.

Horizontal wells have been used to produce thin zones, fractured reservoirs, formations with water and gas coning problems, waterflooding, heavy oil reservoirs, gas reservoirs, and in EOR methods such as thermal and CO2 flooding. The paper includes field examples with cost benefit analysis for various applications.
Through Tubing Rotary Drilling and its Associated Cementing Challenges: A North Sea Experience
Authors: Queiros João G. R. , Benoit Vidick , Cochran Jamie
Published: December 2007

The cementation of any casing string is an integral part of well construction. The main objective of primary cementing is to provide complete and permanent annular isolation from mechanical and chemical stresses during drilling and production stages of the life of the well.

Through tubing rotary drilling (TTRD) technology presents its own challenges to cementing design. The management of the equivalent circulating density (ECD), typically at its highest levels during the final stages of the cement slurry displacement, is a critical parameter of the fluids design process. The use of bi-centre drilling bit design, which achieves a larger open hole size than the pass-through diameter, introduces centralization difficulties and add complexity to the removal of the drilling mud prior to cementing.

The accepted cementation approach for TTRD wells is to formulate low rheological fluids such that, maximum advantage can be taken from the annular velocities for mud removal efficiency.

By challenging the common design practices a design was proposed that combined low and high rheology fluid properties to achieve the objectives set out for the cementing operation of the 2 7/8 inch liner.
Lessons Learnt and Experiences Gained During Two Years of Field Monitoring, Data Integration and Reservoir Management: A Case History of the Mauddud Waterflood, North Kuwait
Authors: Chetri H. B. , Al-Anzi Ealian , Al-Rabah Abdullah , Al-Dashti Hussain , Al-Mutawa Majdi , Chakravarthi Ravula , Brown Matthew , Isby John , Clark Alan
Published: December 2007

The Sabiriyah Mauddud limestone of North Kuwait is a super giant depletion drive oil reservoir. It is undergoing massive development efforts, with a planned enhancement in oil production through phased pattern water flood. The Phase1 development addresses the crestal area (50 km2) of the structure, which was the focus for development efforts in the past. The Phase2 development consists of all remaining peripheral acreage (200 km2), with immense reservoir rock & fluid uncertainties, leading to the identification of reservoir segments for re-appraisal through drilling & testing of new wells.

Re-appraisal work, along with enhanced fluid description, led to the conclusion that a large segment within the Ph2 area, originally considered as a regime of light oil - turned out to be viscous oil. This helped immensely the ongoing Full field dynamic modeling and development planning for this multi billion-barrel reservoir. This also led to the initiation of a Water flood pilot with Non-Conventional Wells in the poorer Ph2 area.

Two years of dynamic performance from producers and injectors located in the Ph1 area enhanced the understanding of the reservoir dynamics. Time lapsed monitoring of static reservoir pressures at key wells during the ongoing water flood, coupled with isochronal Pressure surveys during reservoir shut-downs and RFT data from newly drilled wells in the area during the post injection period, helped to confirm the pressure connectivity across the reservoir and the water flood response. Pressure transient and Production tests gave valuable insights into the well performance and reservoir architecture. In addition to monitoring and maintaining the Seawater injection system at high efficiency level, the regular program of water analysis at the pattern producers provided inferences on water breakthrough trend. Integration of the dynamic data with Production logs & FMIs led to the identification of speed zones with high permeability. This helped to fine tune the Static model.

This paper documents the case history of Waterflood management in a super giant carbonate reservoir and the challenges that had to be met.
Use of Finite Difference Sector Model to Analyse Well Test in the Ormen Lange Gas Field
Authors: Irfan Ahmed
Published: December 2007

The Ormen Lange gas field is intensely faulted which may lead to poor reservoir communication. More than thousand faults have been interpreted and included in the simulation model.

Two exploration wells were tested. The first well test, 6305/7-1 in 1998, showed no boundaries but it is located in a less faulted area. The second well test in mid 2002, well 6305/4-1, showed sealing flow barriers on the pressure data. The objective of this paper is to discuss the result and the methodical interpretation of 6305/4-1 well test in detail and illustrate the importance of numerical finite difference test simulation compared with the analytical interpretations.

Well 6305/4-1 was drilled and tested within a well-defined fault polygon in the North Western flank of the structure. The main objective was to obtain information on fault sealing capacity and to detect possible pressure depletion.

An analytical test interpretation was performed, and the best test match resulted in a no-flow boundary wedge shaped model. The analytical test interpretation gave a good match, but was not able to answer the questions about the geometry and extension of the sealing faults. The numerical finite difference simulation model allows different fault combinations, which are based on realistic geophysical and geological models. A very fine gridded sector model was established, upscaled from a full 3D geological reservoir model. The gridding and Local Grid Refinement (LGR) was carefully investigated and designed.

A large number of numerical test simulations were run, with different fault sealing combinations and fault properties. The best test match suggested that fault might be closer or have different geometry than in the reservoir model.

Reprocessed seismic data improved the data quality and gave an improved imaging of the faulting on the structure. Based on that, fault geometry in the simulation model was updated. This model was further used in obtaining a perfect time/distance match between simulated and real data.

The extensions of sealing faults were thoroughly examined, and a good test match was obtained. Simulation results suggested that three of the faults have to be sealing in vicinity of the well and down-flanks, while a large part of the polygon must be open up-flanks. The results improved and simplified the field development and reservoir management scenarios. These results indicated that faults are open up-flank, and that the gas filled Ormen Lange reservoir is in pressure communication, as also documented by the static pressure data in all the wells.
Optimized Horizontal Well Placement in the Otter Field, North Sea using New Formation Imaging While Drilling Technology
Authors: Tribe Ian , Holm Gordon , Harker Stuart , Longis Christian , Milne Keith , Stromberg Simon , Greiss Rita , Webb Kate
Published: December 2007

This paper demonstrates how new Logging While Drilling (LWD) and Measurement While Drilling (MWD) tools were used to optimise placement of 3 sub-horizontal wells in a faulted, sand-shale oil bearing Brent Group reservoir known as the Otter Field, Northern North Sea, United Kingdom. As the target reservoir layer is only 8m thick and sub-seismic faulting and subtle changes in dip occur in the field, geosteering of the well paths was anticipated prior to commencing drilling. To aid with geological steering of the wells a new LWD tool was run: the azimuthal GR-resistivity device and this provided high-resolution borehole images of formation geology (eg. formation layering and dip, fault location and orientation). Using state-of-the-art mud-pulse MWD telemetry and the world-wide web, the images and other LWD data (eg. porosity) were made available, real-time, to both the onshore and offshore drilling team. Detailed geological cross sections constructed in real-time from the image logs aided steering the wells to the optimum geological locations. One of the three production wells [well 210/15a-T2 (P1)] is used to demonstrate how the imaging while drilling, viewed real-time via the web, was applied. This case study highlights the benefits the technology brought to the drilling operation and field development in terms of efficiency improvements in geological analysis and well steering decision making and maximized oil production through optimum well placement.
Twister Supersonic Gas Conditioning for Unmanned Platforms and Subsea Gas Processing
Authors: Brouwer J. M. , Epsom H. D.
Published: December 2007

Twister™ is a revolutionary gas conditioning technology which has been under development for natural gas applications since 1997. Condensation and separation at supersonic velocity is the key to some unique benefits. An extremely short residence time prevents hydrate problems, eliminating chemicals and associated regeneration systems. The simplicity and reliability of a static device, with no rotating parts and operating without chemicals, ensures a simple facility with a high availability, suitable for unmanned operation.

Full scale test units have been operational since 1998 at five gas plants in the Netherlands, Nigeria and Norway, with varying gas compositions and operating conditions. Test results have been used to improve and validate sophisticated Computational Fluid Dynamic (CFD) models of the complex combination of aerodynamics, thermodynamics and fluid-dynamics. These CFD models have been paramount in improving Twister performance.

Although Twister is a mature technology, Twister BV are developing a second generation Twister design promising a step change performance improvement and reduced pressure drop. Field testing is scheduled for early 2004 with market launch later that year.

The first commercial Twister application will start-up in the 4th Quarter of 2003. Twister has been selected for the dehydration process of a large, offshore gas development in Malaysia. The Twister system design will be described.

Its simplicity makes Twister a key enabling technology for subsea gas processing. The results of a joint industry feasibility study will be reported.
Oil and Gas Recovery Behaviour in the UKCS Basins
Authors: Toole S. T. , Grist D. M.
Published: December 2007

Company management, industry analysts and governments like to have measures of portfolio or national resource performance. Recovery factors are one such means of assessing relative performance. The UK DTI's large database has been employed to assess the distribution of recovery factors with basin parameters. Assessed over time, ultimate recovery factors indicate how expectations have changed for the UK North Sea fields and how new technology and cost reduction have broadly influenced exploitation. Recovery factors also seem to relate to geological facies. Forward prediction of overall growth in recovery factors is of concern for gauging the security of local and world supply. Of course there are caveats or limitations and these are discussed.
New Tools and Fluid Technology Redefine the Application Envelope for Horizontal Openhole Gravel-packing Into a Mainstay Deepwater Completion Method
Authors: Ali Syed , Grigsby Tommy , Vitthal Sanjay
Published: December 2007

Synergy between the horizontal drilling and openhole completion disciplines is required to deliver a reliable high-rate well completion in soft rock formations. This gap has finally been bridged, and the resulting success has allowed it to be considered as a mainstay completion technique in deepwater developments in Brazil. It has shown the same potential for upcoming deepwater developments in West Africa. The technology has also been an enabler for heavy oil developments (API gravity <20 deg, and > 0.934) in Brazil and in the North Sea that otherwise would have been uneconomical.

This paper will address where we started, the evolution of technology, and the lessons learned that are being applied to increase the application envelope and the reliability of this completion method. The review will cover advances in openhole drilling techniques that eliminate hole tortuosity, gravel-pack fluids that can reduce rig time and enhance well productivity, and improvements in downhole tools that have capability to reduce risk while reducing completion cycle time. The review will also examine a possible replacement technology.

The successes already achieved in light of the recent technological advances will be presented in case histories that will verify the reliability that can now be expected.
An Innovative Thermal Production Scheme for Mobile Heavy Oil Reservoirs with Bottom Aquifer
Authors: Rodriguez J. R. , Darche G. , Espinasse J.
Published: December 2007

This paper describes an innovative thermal production scheme, named "Horizontal Alternate Steam Drive" (HASD). This process has been designed to improve the recovery of mobile heavy oils in presence of bottom aquifers, where natural depletion is inefficient because of strong water coning from the aquifer.

HASD is a repetitive pattern using equi-depth horizontal drains acting alternatively as producers and steam injectors: the main recovery process is horizontal steam flooding between successive wells and is more efficient than classical cyclic steam injection.

After the description of the process itself, we will illustrate the performances of HASD using simulation results on simple 2D homogeneous models. We will finally show, using 3D simulations, that HASD increases the recovery in presence of moderately connected aquifers, as compared to natural depletion, and could even improve the performances obtained by more standard thermal processes such as SAGD (Steam Assisted Gravity Drainage).
Effect of Rate and Viscosity on Gas Mobility during Solution-Gas Drive in Heavy Oils
Authors: Talabi O. , Pooladi-Darvish M. , Okazawa T.
Published: December 2007

Some heavy oil reservoirs under primary production have shown higher recovery and production rates than expected. Many studies have shown that gas mobility in these reservoirs is low contributing to improved oil displacement and also that gas mobility may depend not only on gas saturation but also on depletion rate and oil viscosity. Despite the observed effect of oil viscosity and depletion rate on gas mobility, it is not yet clear to what extent these factors affect relative permeability and critical gas saturation.

In this study, we have conducted depletion experiments in a linear unconsolidated sand-pack. Three oils were used, with oil viscosities that varied by a factor of 30. The experiments were conducted at two different depletion rates for each of the oils. Experimental results show that as oil viscosity or depletion rate increases, critical gas saturation increases, gas mobility decreases and oil displacement becomes more effective. Critical gas saturation for all the runs was in the range of 0.2 – 5±1%. Furthermore, it was found that relative permeability to gas decreased as withdrawal rate or oil viscosity increased. The effects of oil viscosity and withdrawal rate were combined in the form of a depletion index, such that oil recovery increased as the depletion index increased.
Streamline-Based Dual Porosity Simulation of Fractured Reservoirs
Authors: Di Donato Ginevra , Huang Wenfen , Blunt Martin
Published: December 2007

We present a streamline-based dual porosity simulator to model waterflooding in fractured reservoirs. Conceptually the reservoir is composed of a flowing fraction, representing the fracture network and high permeability matrix, in communication with relatively stagnant regions. Streamlines capture movement through the flowing fraction while the transfer of fluid from flowing to stagnant regions is modeled as a source/sink term in the one-dimensional transport equation along each streamline.

We discuss different possible forms of the transfer function to represent counter-current imbibition. We implement three forms of the transfer function: the conventional steady-state model and two linear transfer functions that match experimental measurements on cores. An appropriate linear transfer function can be found that gives results similar to the conventional model, matches experiment and gives run times similar to standard single porosity simulation.

We compare the results and run times of the streamline-based approach with conventional dual porosity grid-based simulation. Using an example North Sea dataset for a highly heterogeneous reservoir, we show that streamline simulation gives similar answers to grid-based methods when using the same transfer function, but is at least one to two orders of magnitude faster for models with 100,000 to 1,000,000 grid blocks.
Black Oil Streamline Simulator with Capillary Effects
Authors: Berenblyum Roman A. , Shapiro Alexander A. , Jessen Kristian , Stenby Erling H. , Orr Franklin M.
Published: December 2007

A streamline simulation with capillary and gravity is presented. The black oil streamline simulator [3DSL 0.25 by R.P. Batycky, SUPRI-C group, Department of Petroleum Engineering, Stanford University, 1997] was modified to incorporate capillary effects.

The new simulator has been applied to several simulation cases. We discuss the influence of different factors that may impact performance prediction of water floods. The capillary forces are demonstrated to stabilize the displacement front and increase oil production even in rather viscous-dominated cases.

The new approach can provide a fast and a reliable tool for the simulation of water flooding in low permeable and heterogeneous oil reservoirs as well as for reservoir screening and upscaling studies.
Zulu Pipeline Debottlenecking
Authors: Aritonang Leonardo , Lucich Michael A. , Kurz John E. , Haryanto Kun , Suyanto Ato , Anwar Chairil
Published: December 2007

AVSA and Zulu production areas, located in the NW corner of BP's Offshore Northwest Java, ONWJ, production sharing contract, (PSC), posed a significant challenge for its operator. Production rates had declined significantly, operating costs were creeping up and system reliability was at an all time low. An unreliable compressor pushed gas down an unstable 44.5-mile 20-inch three-phase pipeline from the Zulu Flow station to the PCP central gas-gathering center (Figure-2). At the same time, the AVSA Flow station, located approximately 16 miles to the north, with marginal production, high pour point crude and stranded gas had been shut-in for nearly 2 years due to low export pipeline temperatures associated with low flow rates. A troubleshooting team was hard at work trying to improve Zulu compressor reliability while a team of facilities engineers was trying to figure out how to take water out of the system to reduce pipeline backpressure and mitigate slugging problems. In an attempt to increase production, reservoir and production engineers were testing the economics of ESP recompletion in both fields.

The Asset Manager, frustrated by the lack of progress at Zulu, and under pressure to increase production and improve compressor reliability felt that water removal would help elevate slugging, stabilize pipeline pressure and reduce compression headaches at Zulu. He organized a team to consider water removal options.

What resulted was a not so obvious flow reconfiguration solution that eliminated a major operational defect. The operation was simplified, facilities reliability improved, production increased and lifting costs fell and management could turn its attention elsewhere.

This paper presents a production system operability problem on a very mature offshore oil and gas producing asset, the simple but effective defect-elimination-solution and the resulting benefits.
Integrated Characterization of the Thin-Bedded 8 Reservoir, Green Canyon 18, Gulf of Mexico
Authors: Aniekwena Anthony U. , McVay Duane A. , Ahr Wayne M. , Watkins Joel S.
Published: December 2007

The thin-bedded, channelized-turbidite 8 reservoir of the Green Canyon 18 field (GC-18) had previously been difficult to describe owing to its complex architecture and limitations in seismic data resolution. The reservoir has high rock compressibility. Its complex geology had, before this study, prevented the delineation of its hydrocarbon accumulation and determination of the different resource volumes.

An integrated approach has been used to develop a geologically consistent model of the reservoir. Seismic interpretation and attribute extraction provided the reservoir geometry and stratigraphy, which show the preeminent role of salt tectonics in the shaping of the reservoir before and after deposition. Geostatistical methods were used to construct gross and net thickness maps and to infer lateral variations in the quality of the 8 sand. Lithofacies description from cores showed 3 distinct facies - channel, levee, and overbank deposits - that were sufficient to describe the reservoir. Fine-scale heterogeneity in each zone was determined from core and log lithological descriptions. Truncated Gaussian sequential simulation was performed to distribute facies and reservoir properties throughout the reservoir volume.

The resulting geological model was used to construct a dynamic flow model that matched historical production and pressure data. This work shows the efficiency of the integrated approach in describing complex reservoirs where the internal variability is a major control of flow efficiency. This approach is especially valuable in reservoirs like the GC-18 8 reservoir where the well information is scarce or not uniformly distributed.
Wellsite Information Transfer Standard Markup Language, WITSML, an Update
Authors: Kirkman M. A. , Symmonds M. E. , Harbinson S. W. , Shields J. A. , Will M. , Doniger A.
Published: December 2007

E&P companies are now putting more focus on collaborative asset teamwork to speed and improve decision-making involved with developing oil and gas fields. To facilitate such collaboration, E&P companies are adopting shared, integrated, IT technology to enable multi-disciplinary teams to engage in improved workflow processes across all phases of the oil field life cycle. Much of the data needed to feed these workflow processes can be shared between Service Companies and E&P companies during the planning and execution phases of the wellbore construction process. The "right time" seamless flow of this data between operators and service companies will speed and enhance decision-making.

There have been a number of solutions tried over the past 20+ years, some more successful than others. The WITSML initiative was started in 2000 to update the existing methods for the 21st century and incorporate the lessons learned from previous initiatives. It is sponsored by both E&P operators and oilfield service companies, aimed at providing an industrywide solution for transfer of information between service companies and E&P companies.

This paper will provide a brief review of the WITSML initiative, its original charter and development effort. It will then explore the current status of development for the standard and its API, discuss the current commercial development and the strategy, which aligns the initiative with POSC for the support and enhancement of WITSML. In addition, the paper will briefly discuss future potential areas of benefit for E&P companies, such as WITSML use in the Production Phase of the E&P life cycle.
Simulated Expert Interpretation of Regional Data to Predict Drilling Risk
Authors: Balch R. S. , Weiss W. W. , Ruan T. , Weber S.
Published: December 2007

Incomplete or sparse information contributes to high levels of risk for oil exploration and development. To more accurately and consistently predict drilling risk, a degree of automation of data analysis may be helpful. "expert systems" developed and used in several disciplines and industries, have demonstrated beneficial results in modeling the decision making process of human experts. A state-of-the-art "expert" exploration tool using computerized multidisciplinary databases, expert developed "rules", and regional data maps -generated using artificial neural networks, has been developed.

The system employs a web interface for users to select prospect(s) of interest and to allow data review or addition, and includes security to maintain the sanctity of proprietary information. Two types of rules are applied to the data. Heuristic rules are generated directly from engineering, geophysical and geological databases. Expert rules are developed through interviews with successful prospectors. Rules are applied in four categories: Regional Indications, Trap Assessment, Formation Assessment, and Oil Price. Some users may elect to not factor in certain aspects, or to use their own values.

Each of the sub systems assigns a numerical score based on the answers to individual "expert" questions. Results are then combined to form an overall risk assessment associated with the selected prospect(s). These scores can be derived from "crisp" mathematical computations, "fuzzy" analysis, or a combination of the two.

This expert system can help companies of all sizes, to more efficiently evaluate prospect quality, and thus more rapidly eliminate poor prospects and generate new production from favorable prospects. The initial system has been initially tuned for the Brushy Canyon formation, Delaware basin, New Mexico.