bluuebunny/crossref_metadata_2025 huggingface dataset:
A Caustic Steamflood Pilot-Kern River Field
Authors: Robinson R.J. , Bursell C.G. , Restine J.L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

From October 1973 to June 1976 a caustic steamflood pilot test project was operated in the Kern River Field of California. The test was conducted in nine adjacent five-spot patterns and utilized Sodium Hydroxide as an patterns and utilized Sodium Hydroxide as an additive to the injected steam.

The purpose of this paper is to present and discuss the operation and results of the pilot project. Initial research and planning pilot project. Initial research and planning processes are described in addition to processes are described in addition to comparison of the pilot production response with other similar patterns in the same area of the field.

Tracer and testing programs were initiated in the later stages of the pilot to provide additional data for analysis of the provide additional data for analysis of the project response. This information is project response. This information is presented along with discussions which presented along with discussions which describe the behavior and movement of the Sodium Hydroxide through the reservoir.

From the results of this pilot, recommendations are made concerning laboratory testing and field applications of chemical additives in a steamflood project.

Introduction

The use of a caustic additive for enhancement of oil recovery has been suggested, discussed and tested for several years by various individuals. Most of the literature focused on enhancement of waterflood response by using a chemical additive that would either change the interfacial tension between oil and water, adjust the wettability of the reservoir system, or increase sweep efficiency, all of which can be accomplished with a caustic.
Numerical Modeling Of The Wairakei Geothermal Reservoir
Authors: Horne Roland N. , O'Sullivan Michael J.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

In order to achieve a better understanding of the Wairakei geothermal reservoir and of others of similar type, the current investigation considers the problem of a hypothetical geothermal aquifer that depletes the fluid saturating its upper regions during production. This depletion leads to the characteristic depressurization and drawdown of the liquid surface observed at Wairakei. This effect is significant in that the subsequent appearance of a horizontal pressure gradient may cause the premature shutdown of the bore field due to the premature shutdown of the bore field due to the encroachment of colder ground water.

In fact, the results of the modeling show a different behavior, emphasizing the vertical movement of the saturating hot fluid as a more important effect. The model gives an indication of the time the reservoir will take to reach pressure equilibrium and its output at that pressure equilibrium and its output at that time.

Problems associated with the numerical procedures are considerable even though the procedures are considerable even though the model is single phase and axisymmetric, and the value of such an intricate numerical model is tenuous. By using a simpler model, replacing the moving surface by an encroaching region of cold water, it is possible to obtain a lower bound for the useful-life of the system and also to examine the possible effects of recharging the system.

Introduction

The numerical investigation of geothermal reservoirs has been performed on one of two levels - first, attempts to model exactly all the geological properties and fluid and thermo-dynamic behavior of the system or, second, fundamental models that include only the effect deemed significant. Although some success has been made with the first approach, for example, the comprehensive, two-phase, rock matrix interaction model of Garg et al. and the simpler model of Mercer and Faust, the current investigation favors the second approach. There are advantages in avoiding a full simulation since little information concerning the physical system is available from below the level of the well bases, so that it is only possible to represent conditions in the upper possible to represent conditions in the upper reservoir.
Analysis Of The Response Of Geothermal Reservoirs Under Injection And Production Procedures
Authors: Lippmann Marcelo J. , Tsang Chin Fu , Witherspoon Paul A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A major problem facing geothermal operations is the disposal of large quantities of relatively cool waste geothermal waters. Environmental regulations may require reinjection into the reservoir. Since the reservoir is thus cooled around the injection wells, there is some reluctance to reinject into wells that might be used for future production. production. In this paper the response of a liquid-dominated geothermal reservoir to injection and production from a single well is studied. Different production from a single well is studied. Different injection-production schemes are analyzed to explore how to minimize temporary cooling around the injection well and to optimize thermal recovery. The pressure response is also calculated, and found to be affected significantly by temperature-dependent viscosity variations. This will have implications on well-test methods for geothermal reservoirs. Vertical consolidation of the geothermal system during fluid withdrawal is also discussed, showing the need to establish previous stress history before attempting to previous stress history before attempting to predict the reservoir deformation. predict the reservoir deformation. The transport of heat and fluid through a porous reservoir is computed using a numerical porous reservoir is computed using a numerical model developed at the Lawrence Berkeley Laboratory. The one-dimensional consolidation theory of Terzaghi has been coupled to the heat and fluid flow to calculate reservoir compaction. attempt is made to model chemical reactions or precipitation that might occur when waters of a precipitation that might occur when waters of a different temperature and salinity are injected into the reservoir.

A. Introduction

A major problem facing geothermal energy development is the disposal of large quantities of relatively cool waste geothermal waters. Operators are reluctant to reinject these fluids as they could irreversibly cool the reservoir around the injection wells and affect nearby producing wells.

Gringarten and Sauty used a two-dimensional semianalytical model to investigate the effect of reinjection wells on neighboring producing wells. Tsang, and Witherspoon used the same model to suggest the screening effect that may be found in a multiple-well system. However, this model assumes a steady fluid-flow field, neglects gravity and, even more important, ignores the dependence of parameters (such as viscosity and density) on temperature variations. Thus a detailed understanding of the behavior of a geothermal reservoir cannot be expected with this semianalytic approach.

Realistic two- or three-dimensional numerical models have been developed to analyze liquid-dominated geothermal systems (Mercer and Pinder; Pritchett et al.; Sorey, and others). Pritchett et al.; Sorey, and others).
A core based comparison of the reaction characteristics of emulsified and in-situ gelled acids in low permeability, high temperature, gas bearing carbonates
Authors: Lynn Jack D. , Nasr-El-Din H. A.
Published: December 2007

There are a number of acid formulations that will generate deeply penetrating wormholes in carbonate formations. Two of the most recent advances are diesel emulsified acid (DEA) and self-diverting polymer/HCl (in-situ gelled acid, or GA). The acid volumes required for propagation of the wormholes, as well as the characteristics of the wormholes are significantly different in each of these formulations. Two different service company implementations of GA, and one inhouse developed DEA formulation were evaluated for stimulation of a high temperature (250°F, 121°C), low permeability Saudi Arabian gas and gas condensate producing carbonate.

In this paper, the reaction characteristics of DEA were compared to GA formulations using reservoir condition core floods. The characteristics of the acids that were compared included wormhole propagation rates, volumes of carbonate consumed by the acids, wormhole geometric characteristics, and pressure response during injection. Since the acid formulations called for 28 percent HCl acid concentrations, high temperature stability and corrosion control chemicals of the packages were evaluated.

The core study found that the GA formulations enhanced the permeability of core samples significantly more then the emulsified acid. The DEA was the more stable of the acid formulations at 250°F. Both of the GA formulations showed some degree of separation of the corrosion control components at reservoir temperature.

The GA was found to require larger volumes of acid to achieve an equivalent penetration distance versus the DEA, and logically, the GA dissolved a larger volume of rock per volume of acid injected. The DEA has a higher rate of wormhole propagation and the DEA leaves no residual material in the generated wormholes. The GA left a residuum of polymeric material in the wormholes even after high rate injection condensate.

Iron precipitation was noted on both the core injection and production faces with all of the acids after spending. The two acids types showed individual characteristics that can be applied to acid frac applications, but full understanding of the behavior of each, tested with specific reservoir core is required for a correct acid selection to be made. In specific applications, both acid types can be combined in a multiple stage treatment to result in significant enhancement of acid frac simulations.
Improved Horizontal Well Placement and Performance Using a Bit Inclination Measurement Tool
Authors: Muritala Lateef , Onwuazo Charles , Adewumi Femi , Aibangbe Osaretin
Published: December 2007

Accurate geological placement of a lateral in the sweetest portion of the reservoir plays a major role in optimizing production rates and increasing recovery from horizontal wells, particularly for complex reservoirs with heterogeneous features. Horizontal wells have thus been routinely steered both geologically and geometrically using evaluation measurements from conventional bottom hole assemblies with sensor points some 50 feet away from the bit. This implies that correction runs and it’s effective response time and footage will be dependent on directional drilling personnel proficiency and tool performance relative to formation type. It is not surprising thus, that a sizeable part of the reservoir is drilled sub-optimally, and in some cases the eventual well bore undulation has caused impossible completions, developed water sumps and have also given birth to speedy breakthroughs of gas and water. All of these have impacted production negatively, and caused unnecessary oil deferment, early work-over and associated cost overrun on budget.

The ideal option would thus be to minimize the undulation while geo-steering the lateral along the sweetest portion of the reservoir in an attempt to minimize attendant production problems and hence allow efficient and early completions.

A tool has been developed which measures well bore inclination 1 foot away from the drilling bit. Shell West Nigeria introduced the At bit Inclination measurement tool to horizontal well drilling on the Opukushi 26 well in March 99. This was to complement multiple depth propagation resistivity and quadrant density-neutron measurements while drilling utilized in horizontal evaluation, to enable full wellbore geologic steering with optimized response time for correcting changes in the desired direction. The result is a significant improvement in the ratio between actual versus predicted production figures as compared to previously drilled wells executed without the combination measurement. It also aided geosteering decision, improved directional performance and enhanced delivery of better quality well.

This paper therefore reviews the SPDC horizontal wells experience in identifying the impact of deviation profiles and lateral placement with respect to production performance, and how the use of the near bit inclination tool along with the formation evaluation measurements has resulted in noticeable improvement.
Short-Radius Drilling Performance Improvement in Algeria
Authors: Neal P. , El-Demerdash A. , Benamor B. , Zeghouani R.
Published: December 2007

This paper describes the benefits resulting from collaborative efforts in solving short radius drilling challenges in the Hassi Messaoud field in Algeria. The core of the collaboration was a team of engineers and geologists from the operator, bit manufacturer, directional drilling and measurement while drilling (MWD) contractors. The team shared information on the characteristics of the field, identified directional problems related to motor selection, adjusted bit selection, and utilized directional drilling expertise, resulting in a reduction in overall drilling cost of over 30%. The following case study highlights cost savings and technical advancements achievable through close cooperation between the operator and service companies.
Improving Drilling Performance by Applying Advanced Dynamics Models
Authors: Dykstra M. W. , Neubert M. , Hanson J. M. , Meiners M. J.
Published: December 2007

Drilling dynamics models play an important role in drilling performance optimization. These models can be classified as engineering tools or research tools, depending on functionality. Engineering tools are designed for everyday use; they provide estimates of important parameters for planning purposes, such as natural frequencies and buckling loads. Research tools describe the physics of the problem more completely, and thus are more powerful. They allow complex phenomena to be studied in great detail, but require a greater investment of time and effort. Both types of models require validation, either through laboratory testing or controlled field tests. Once confidence in the models is established they can be used in a number of ways, including component design, bottom hole assembly (BHA) design, and investigation of component contributions to overall drilling system performance.

Application of advanced dynamics models within one major service company has provided some valuable lessons. Examples include: (1) polycrystalline diamond compact (PDC) bit designs can be adjusted to minimize impact damage to cutters; (2) roller cone designs can be adjusted to reduce off-center running tendencies; (3) BHA stabilization can be optimized to protect sensitive downhole equipment; (4) BHA designs that are unstable can cause rapid bit destruction; (5) operating parameters can be adjusted to improve performance of sub-optimal drilling systems.

Case studies from disparate drilling applications around the world have demonstrated that performance can be improved by applying lessons learned from advanced dynamics models. Operators have experienced significant savings in rig time stemming from reduced tool failure frequency and increased drilling efficiency. Greater tool longevity and reduced maintenance costs have also benefited the service company.
Research Into Lubricity, Formation Damage Promises to Expand Applications for Silicate Drilling Fluids
Authors: Alford S. , Dzialowski A. , Jiang P. , Ullmann H.
Published: December 2007

Silicate drilling fluids have been used for more than 60 years. While the early versions of silicate-base systems proved very inhibitive, controlling mud properties was difficult because proper polymer additives were not available for maintaining rheology and fluid loss control. Furthermore, the solids control equipment available at the time was ineffective in removing solids. During the last decade, silicate-base systems have been re-engineered to provide a state-of-the-art and environmentally acceptable, water-base system that provides the inhibition approaching that of an invert emulsion fluid.

The proposed mechanism of inhibition is the surface adsorption and chemical reaction of the silicate polymer with the formation surface. This "coating" effectively provides a thin pressure and chemical barrier on the surface of the wellbore. This formation/silicate interaction has raised a number of concerns regarding both the lubricity and the formation damage potential of the fluid.

This paper investigates systematically both the lubrication characteristics of the fluid and the effect of silicate-base systems on formation production and evaluation. The results show promise in expanding the application of silicates as reservoir drill-in fluids and in the drilling of critical high-angle wells where lubricity is a primary design criterion.

The data obtained in this study utilizes purpose-built lubricity and formation damage equipment to critically look at the problems. From this investigation the authors will reveal that the coefficient of friction of silicate fluids, as observed in the laboratory and measured in the field, does not differ significantly from that of other water-base fluids.

Furthermore, the thin physical and chemical barrier formed during the reaction of the silicate polymer with the formation surface prevents fluids and fine particles from migrating into the formation, thereby minimizing damage to the producing zone.
Application of Multilateral Well Technology in the Deep Waters of the Campos Basin: History and Probable Evolution
Authors: Sotomayor Gabriel , Oliveira Ronaldo , Alves Ivan
Published: December 2007

This paper presents some of the experience of drilling and completing level 4 and 5 multilateral wells in deep waters of the Campos Basin, in the last three years. It presents the reason for this initiative, a general description of the several types of junction building processes (both milled and pre-milled window systems) and some aspects of the wells that were drilled and completed: the Bonito well (water depth:200m); Voador well (water depth: 565 m) and the two Barracuda wells (water depth: 802m/ 850m). This paper also shows the lessons learnt during these complex projects and concludes that the multilateral well technology became a viable alternative for subsea development.
A New Look at Deepwater Drilling Problems Combined with New PDC Technology Produces Savings of $5.9MM
Authors: Newhouse C. C. , Fielder C. M.
Published: December 2007

During project execution planning for a Gulf of Mexico (Green Canyon) deepwater project, the well construction team looked at all possible options that might reduce time on each well. This investigation indicated that the biggest opportunities in the drilling phase were increased ROP and reduced number of trips.

The original plan had included the use of underreamers and roller cone bits. It was known that PDC bi-centers were a cost effective replacement for underreamers due to their ability to simultaneously drill and underream. Also, that ROP was higher with PDC bits (both bi-center and conventional PDC bits). Previous use of PDC bits had, however, resulted in hole-cleaning problems due to the large volume and type (gumbo) of cuttings. Problems were also historically encountered with PDC directional characteristics, especially kicking off in the larger hole sizes and angle dropping in the tangent sections. Based on the recent introduction of new PDC technology it was decided to take a new look at making PDC bits more effective.

To counter the problem of hole cleaning, it was decided to increase flow rates by utilizing a larger drill string. In the upper section of the well where underreaming was planned, a new type of bi-center was used. The bi-center used new technology that allowed it to drill out (saving an additional trip over conventional bi-centers). In the lower section, a radically new PDC drill bit design was used that contained features to significantly increase ROP. Both of the new PDC designs contained new features to significantly improve directional characteristics. A variety of other improvements/modifications are mentioned in the paper.

Results: The new technology bi-center bits (17 × 20 and 14 ½ × 17 ½), provided the biggest time savings by eliminating trips, producing very high ROP, and successfully kicking off and building angle (one case as high as 68 degrees). The new PDC drill bits used in long tangent sections (one was 9300’ at 63 degrees) had ROPs that in most cases doubled that of similar offsets while reducing slide times to as little as 1%. The new plan resulted in four wells being drilled in 115 days less than the original project AFE estimates (52% reduction), for a savings of $5.9MM.
Reducing Drilling Costs in Deep-Water Gulf of Mexico Utilizing Two Piece Drill Out Reaming Technology
Authors: Watson Patrick A. , Kolstad Eric S. , O‘Grady Thomas T.
Published: December 2007

The application of modified reaming technology in Mississippi Canyon, deep-water Gulf of Mexico (GOM) has had a beneficial impact on drilling costs. The ability to drill cement and associated downhole float equipment with steerable ream while drilling (DOSRWD) tools has become increasing important in deep-water GOM drilling. The extra trip required by conventional bi-center and eccentric tools adds costly "flat" time to a well’s drilling program. Additional improvements in the eccentric bit’s geometry and cutting structures has reduced the number of trips and significantly lowered drilling costs. Traditionally, when a ream while drilling system was used, the operator drilled the cement and float equipment with a pass through size bit, then tripped out of the hole to pick up the ream while drilling bottom hole assembly. For example, float equipment and cement in 9–5/8" 53.5# casing was drilled out with an 8–1/2" bit. A trip was then made to pick up a standard 9–7/8" SRWD bottom hole assembly.

The DOSRWD’s ability to drill cement and float equipment inside casing and then continue drilling ahead, plus the option to use either a tricone or PDC pilot bit depending on directional requirements and formation type make it the appropriate tool for the application. Water-based fluids are preferred in the upper hole section while synthetic mud is used deep in the wellbore. Because of balling concerns in WBM and stringent directional requirements, the operator utilizes metal bearing seal steel tooth pilot bits in most cases (IADC 117). The authors will document rig cost savings ranging from US$40,000 to $105,000 per trip in some applications with total savings exceeding US$388,000 in some instances.
Through Tubing Well Construction
Authors: Moss Gary , Kuyken Chris , Maessen Frans
Published: December 2007

The Northern Business Unit (NBU) of Shell U.K. Exploration and Production (Shell EXPRO), operating on behalf of the Shell / Exxon Mobil co-venture, comprises the Northern North Sea assets of Brent, Cormorant, Tern, Eider and Dunlin platforms and several sub-sea developments. These mature assets with increasingly marginal accumulations to target have required a broad approach to reduce drilling cost and or increase the NPV from a well bore. This has been successfully achieved by a synergetic approach of the combination of optimising the contracting strategy, implementation of the Deliver The Limit™ Philosophy and by the speedy implementation of novel technology. One of these technologies is Through Tubing Drilling (TTD). In the NBU this enabling technology has been applied since 1996 both in the form of Coiled Tubing Drilling (CTD) as well as Through Tubing Rotary Drilling (TTRD). This has yielded a total of 8 TTD applications (6 CTD, 2 TTRD) making the NBU a dominant North Sea TTD operator who has achieved a unique learning curve.

The objective of this paper is to explain the TTD work that was performed in the NBU and how this has evolved from primarily CTD into TTRD. This change took place as a result of major changes in the business case as well as in reservoir conditions having a large impact on the risk of drilling these wells both from a technical and cost perspective. The paper covers the full NBU TTD Campaign since 1996 but the main focus will be on the Brent CTD campaign (1999) and North-Cormorant CN18S-5 TTRD well (2000). Key learning from a business perspective is that the CTD wells in Brent will be challenging to drill for less than £2.5 million whilst the latest North Cormorant TTRD well was drilled for £1.5 million with significant scope for further cost reduction.
Design of Water Based Drilling Fluid Systems for Deepwater Norway
Authors: Sørgård Eirik , Alterås Eva , Fimreite Gunnar , Dzialowski Andrew , Svanes Grete S.
Published: December 2007

The technical demands placed on drilling fluids used in the deep waters of Norway differ dramatically from those encountered in any other deepwater basin. Unlike the deepwater of the Gulf of Mexico, West Africa or Brazil, seafloor temperatures here can dip as low as –2.5° C (27.5°F), with low ambient surface temperatures the year round. These characteristics combined with constantly changing sea conditions and some of the world's most stringent environmental restrictions, makes the engineering of drilling fluid systems for Norwegian North Sea wells an arduous effort.

This paper describes the innovative development and qualification of a water-base drilling fluid system engineered for a well to be drilled in 837 meters (2745 ft) of water off Norway. The pre-qualified fluid was required to inhibit hydrates under normal drilling conditions and possess excellent shale inhibition characteristics to support hole stability and avoid bit balling. Since the primary objective was to obtain a non-contaminated formation water sample, the system must possess superb fluid loss control so the operator could avoid a full drill stem test, thereby saving some US$8 million. Furthermore, the qualified system would have to meet local environmental regulations for offshore discharge of cuttings and excess fluids.

The authors will discuss the development protocol, the qualification of the novel fluid system and its application in the technically demanding Norwegian well. During the development phases, two hydrate testers were qualified and employed in both designing the fluid and to monitor its hydrate inhibitive tendencies during drilling. In addition, the particle size distribution and polymer concentration were engineered to reduce the filtrate invasion, while polymers were specially selected for improved rheological parameters to cope with the cold temperatures. The behavior of a number of glycols and salts were characterized prior to the start of drilling.

The practical approach to qualify the novel fluid system will be explained in detail, emphasizing its use as a guideline to help non-fluid specialists design drilling fluids for this unique deepwater environment
Enhancing The Value of The Irong Barat Field through An Integrated Team Approach
Authors: Bin Yusoff Emry Hisham , Cheng-Sun Ong , Chakravarthy S. , Jamiran Mohd Khalid
Published: December 2007

Irong Barat Field, located in the southeastern part of the Malay Basin, was discovered in 1979. The field structure is a complexly faulted WNW-ESE trending asymmetrical anticline dissected into four major fault blocks by a set of NNW- SSE trending normal faults, with additional subsidiary faults further segmenting the field in the central fault blocks. Oil bearing reservoirs are encountered in the H and I reservoir groups, with the bulk of reserves and present production from the H-50 unit. Existing development, 18 wells from a manned Irong Barat A platform, is mainly confined to the structurally less complex Fault Block I with 2 wells completed in the adjacent Fault Block II. Production started in November 1983 and more than 80% of the estimated developed reserves have been produced. Currently the field is producing at 11 MSTB/D.

A multi-disciplinary team was formed to identify and mature the hydrocarbon potential of the complexly faulted undeveloped Fault Block II, III and IV and also the remaining opportunity in Fault Block I. The 3D seismic, appraisal well, production and well data were reviewed and a few development options were considered. As a result of the integrated field review, 2 additional drilling programs are planned to further develop the field, which involve drilling of 20 new wells from existing Irong Barat A and a new Irong Barat B platform.

This paper discusses how the integrated field review enabled the team to further develop the field through better understanding of the reservoir and geology and better managing of the uncertainties.
Reservoir Saturation Monitoring in the Attaka Field
Authors: Moinard L. , Boehm M. , Turner S.
Published: December 2007

The Attaka oil and gas field has been in production since 1972 and has produced nearly 600 MMBO and 1.3 TCFG.

In order to maintain production, wells are worked over regularly to shut out water production and to open new reservoir intervals. Determining the amount of gas, oil and water before working a well over is essential. Traditional methods using thermal neutron decay do not work for oil because formation waters are relatively fresh and the contrast between oil and water is too small for quantitative analysis.

Carbon/oxygen logging overcomes the low-salinity limitation in all but low-porosity and very shaly sands. It has been carried out routinely in selected intervals in the Attaka field since 1999 and has become an integral part of reservoir monitoring. This paper presents examples from several wells in the Attaka field, where hydrocarbon saturation from carbon/oxygen (C/O) logging was critical to the successful recompletion of the well. In particular, the drilling of the UA-7RD1HZ intermediate radius oil well was dependent upon accurate assessment of the oil leg location and thickness.

UA-7HZ was logged in the Main Deltaic 44-5A reservoir with the Schlumberger RST tool (combined thermal neutron and C/O log) in March 2000. The resulting log clearly showed an oil leg with enough remaining volume to warrant drilling an intermediate radius horizontal oil well. That well was successfully drilled later in March and has produced enough oil to date to pay out the re-drill. Decline curve analysis indicates that the total volume of oil to be recovered will be nearly 100 MBO. Because this reservoir was scheduled for gas-cap blow-down, this 100 MBO would not have been produced without accurate measurement of the remaining oil leg.
Study of the Mechanism of Polymer Solution With Visco-Elastic Behavior Increasing Microscopic Oil Displacement Efficiency and the Forming of Steady "Oil Thread" Flow Channels
Authors: Wang Demin , Xia Huifen , Liu Zhongchun , Yang Qingyan
Published: December 2007

In this paper, the visco-elastic characteristics of polyacrylamide solution have been studied experimentally. The mechanisms of the effect of polymer solution with visco-elastic characteristic on each type of residual oil after water flooding are analyzed and the mechanisms of polymer solution with visco-elastic characteristic increasing microscopic oil displacement efficiency are studied. By the analysis of microscopic experiments of percolating flow, corresponding relationships between the characteristic parameter describing the visco-elastic behavior of polymer solution and displacement efficiency of residual oil in "dead ends" are given. It is shown that the larger the visco-elastic behavior of polymer solution, the higher the displacement efficiency of residual oil in "dead ends".

A phenomenon that is not seen during water flooding is observed during polyacrylamide solution flooding in the microscopic experiment of percolating flow, that is, residual oil can be pulled into "oil threads" by the polyacrylamide solution. So a new type of oil flow channel, i.e. "oil thread" channel, can be formed and residual oil flows downstream through the "oil thread" channel. The probability of forming a steady "oil thread" flow channel in polymer flooding is also analyzed theoretically and proved.

The research indicates that the mechanism of polymer solution microscopically increasing oil recovery is due to the visco-elastic characteristic of the polymer solution, the sweeping force acting on the residual oil for the visco-elastic polymer solution is larger than that of water. The residual oil is not pushed out by the polymer solution but pulled out by the polymer solution. It is also found that every type of residual oil after water flooding can be decreased by visco-elastic polymer solution, and the larger the visco-elastic property, the stronger the capability of the polymer solution to "sweep out" the residual oil.

In brief, the results indicate that polymer flooding can not only macroscopically increase the sweep efficiency but also microscopically increase the oil displacement efficiency and a new type of flow channel, "oil thread", can also be formed.Besides new understanding on the mechanism of the flow of fluid through porous media and the displacement of residual oil, the above results should be beneficial to designing new EOR methods to further increase the recovery of oil fields.
Multi-Lateral Well Modelling to Optimise Well Design and Cost
Authors: Lee S. S. , Veeken C. A. M. , Frens Ante M.
Published: December 2007

In prolific gas reservoirs with strong aquifer drive, water coning is often the determining factor in well productivity and ultimately, gas recovery factor. One of the main drivers in optimising the field development in these cases is to reduce the drawdown of the wells and consequently, a horizontal well design is often used. It is the case, however, that in such highly permeable gas fields extending the horizontal length beyond 1000-2000 ft often does not help to improve well productivity any further, as well bore friction becomes the constraining factor. This paper presents a cost effective and simple solution to increase well productivity by 60% compared to single horizontals at a marginal cost increase. A simple level-1 dual lateral with large bore casing-flow well design has shown to be able to deliver the additional productivity at only a 5-10% incremental increase in cost. Furthermore, we present the results of the numerical simulation that helped to justify the well design and to deal with interference between the branches.
Development of a Marginal Gas-Condensate Field Using a Novel Integrated Reservoir and Production Management Approach
Authors: Nygård Ole , Kramer Colin , Kulkarni Raghavendra , Nordtvedt Jan-Erik
Published: December 2007

This paper outlines how data acquisition, data analysis, and control actions, can be implemented remotely and in real time to enhance the reservoir and production management process. System components, their integration, and the opportunity they offer to implement reservoir and production management work processes based on real-time data will be discussed and exemplified. We will show how such a system can be implemented on a field. For this, we will utilize the planned installation of such a system in the Huldra gas/condensate field in the Norwegian sector of the North Sea. We will describe how "closed-loop control" for reservoir and production management will be implemented on this field, and give examples from work processes on real-time data leading to faster and better decision support, and, finally, decision making and implementation.
"Pozoteca" Integrated Management of Technical Information on Exploration and Production Wells
Authors: Durán C. F. , Viracachá C. O. , Bejarano A. , Blanco F. A. , Tapias O.
Published: December 2007

The imminent necessity of reactivation of the exploration activities and evaluation of geologic prospects potentially producing hydrocarbons in Colombia, depends on several factors, among those it is counted the most valuable and important, the readiness of information that guarantees an integral knowledge of the areas of interest.

Keeping in mind the existence of computer tools such as the web of the information (WWW) and technological advances in integration, analysis, processing and data administration, ECOPETROL (Oil Colombian Company), and their enclosed Vice-presidency of Exploration, have joined efforts in the process of integration of complete information of wells coming from diverse sources. Furthermore they used brand new technologies in areas of document preservation, storage, organization, structuring, consults and data analysis.

This document shows the change and benefits of a traditional system of location and recovery of information of wells vs. an integrated system of handling wells information via electronic Intranet/Extranet/Internet. The user can consult his area of interest starting from reliable well coordinates, to gather partial or total well logs information, by zones or all depth, to locate the available seismic information, besides the geologic and operative information gathered in drilling processes, logs services, completion and wells production tests.

Additionally the modules, that conform the only POZOTECA of the country, are presented with their structure and the processes of documents capture: vectorizing and digitizing, unification of parameters of acquisition and processing, strategies of databases integration and navigation systems and consults of this valuable key information for the development of the country. This outline according to international experts’ concepts is an unique model that has not been developed in another country of the world reason why it will be very useful for the implementation of similar processes in the national and international oil industry, highlighting that it is a work developed basically with the contribution of the knowledge of national technological base companies.

The philosophy of acquisition, updating, administration, consults and handling of the POZOTECA establishes applicable work protocols to other areas of the knowledge in the oil industry. It guarantees the resources optimization; decrease of costs and it avoids misinformation. Equally, the system increases the productivity of the E&P workers and the discovery of new reserves and business opportunities. The economic and technological contribution of the present project is invaluable and it can be used immediately.

The system is available for data mining and data analysis1,2 processes. It is established architecture for data transformation with features clearly defined e.g. data type, unity and semantic aspects into the E&P environment.
Novel Method for Monitoring and Controlling Asphaltene Deposition in Crude Oil
Authors: Means M.
Published: December 2007

Baker Petrolite has developed a new proprietary method of detecting the asphaltene content of crude oil. The method employs a spectroscopic probe detection technique that measures the amount of dissolved asphaltenes in the crude directly without sample preparation. The device is suitable for both discrete or continuous in-process sample measurements. Laboratory and field test data are presented. The new technique compares with traditional methods of asphaltene characterization including IP-143 extraction gravimetric analysis and ADT spectroscopic methods. This technique, combined with asphaltene inhibitor/dispersant injection control, provides a novel method for the control of asphaltene deposition in crude oil production systems.
The Three R's of Oil Production for the 21st Century
Authors: Lampe S. W. , Veale T. M.
Published: December 2007

For an industry steeped in tradition and energized by innovation, this might be both the best of times and the worst of times to be an oil producer. At the same moment that California is engaged in a high profile energy crisis, the dawning of the 21st century marks a transformational period for oil production.

Producers are undergoing the ultimate challenge — finding technology solutions that will carry forward the promise of what we call the three R's of oil production: reducing O&M costs, demonstrating higher operating reliability compared to existing technologies; and effectively revolutionizing the approach to prime power production.

With less control of operational costs than ever before, how will producers control energy costs, gain free fuel and clean power while ensuring long-term business viability and profit?

In a word: microturbines.

For producers of oil production, microturbines represent a technology breakthrough and "green" opportunity for the producers’ bottom line.

The commercial introduction of microturbines by Capstone Turbine Corporation late in 1998 sparked a new generation of enabling innovation. Two companies are now vying for global market share: Capstone and Honeywell Power Systems.

Capstone emerged as the technology leader in development and commercialization of ultra-low-emission microturbine power systems that are particularly well suited for oilfield needs.

Combining miniaturized jet engine technology with digital power electronics, the simple design of a microturbine belies the fact it solves a variety of onsite power generation needs while simultaneously improving energy economics. Capstone's air-cooled design and patented air bearing technology eliminates the need for any liquid subsystems while mitigating the high maintenance costs and downtime associated with reciprocating engine generator sets.
Effect Of Grid Size In The Compositional Simulation Of CO2 Injection
Authors: Camy J.P. , Emanuel A.S.
Published: December 2007

Introduction

Numerical dispersion is a well known problem which can cause serious difficulties problem which can cause serious difficulties in simulating the movement of a sharp saturation front. In compositional simulation, the problem is increased by the dispersion of composition fronts as well as saturation fronts.

Several authors have discussed dispersion effects in misable simulation studies.

Nolen noted serious dispersion effects in a compositional study of miscible displacement and used a method of characteristics approach to improve front tracking. Fussell et al. noted a requirement of 100 cells in a cell-to-cell flash model. Todd discussed the use of mixing coefficients and pseudo relative permeability curves to reduce dispersion effects in a 3 or 4 component simulator.

The investigation reported in this paper describes techniques for deriving paper describes techniques for deriving pseudo-functions for reducing dispersion pseudo-functions for reducing dispersion and mixing errors in a multicomponent finite difference compositional simulator. Our technique is aimed at deriving pseudo functions from small fine grid models for use in large scale coarse grid models. The pseudo functions bring the accuracy of the fine grid into the coarse grid calculations. The economics of simulating compositional effects in reservoir simulation will thus look more attractive. In this respect, our approach is similar to that of Cook. Our approach differs from Cook in that the pseudo functions correct a broader range of pseudo functions correct a broader range of numerical problems and are intended for compositional rather than black oil simulation.

Our particular concern is for CO2 injection into reservoir oil, but we believe the pseudo function concepts can be extended to most gas injection problems.

THE GRID SIZE PROBLEM

Among the many parameters that control dispersion and mixing problems, cell size is one of the most important. It is usually recognized that the smaller the grid size, the smaller the dispersion and mixing error. The three most important reasons in a compositional simulator for model results to vary with cell size are:Numerical DispersionNonlinearity of the flash equationNonlinear dependence of saturation and total mobility

Numerical Dispersion

The causes and effects of numerical dispersion in finite difference simulation have been discussed extensively in the literature. In a compositional finite difference simulator, dispersion affects both saturation and composition. The problem becomes further complicated in a problem becomes further complicated in a WAG operation where water and gas are injected alternatingly. If the injected slugs are small, a fine grid will be needed in order to define each slug by at least one or two grid blocks. If slugs are small and the grid coarse, several slugs will be mixed in few cells, as though water and gas had been injected simultaneously. A WAG displacement process cannot then be adequately represented.
The Demand for Natural Resources Revisited
Authors: Vogely William A. , Bonczar Elizabeth Semon
Published: December 2007

Two models for explaining the demand for natural resources are developed for the period 1900–1969. The first model relates demands for total natural resources and five sub-categories to the size of the economy, real prices, and the state of technology. The second model relates the intensity of use of resource categories and sub-categories to real prices and technology. The major findings are that the United States has been using raw materials more efficiently through time during this century and that the current state of the data base is not sufficient to choose between alternative hypotheses of the determinants of intensity of use. Directions of future work are indicated.

PART 1 PART 1 OVERVIEW

The subject of raw material demands with respect to economic growth has become an increasingly important one, especially in the area of energy. In 1974 in a paper presented before the Council of Economics, Dr. Malenbaum proposed a law of demand for minerals, including proposed a law of demand for minerals, including fuels. His thesis was that the intensity of use of a mineral; i.e., consumption of the mineral per unit of gross national product (GNP), is a function of GNP per capita. Further, he stated that the shape of this function was an inverted "U"; that is, as per capita GNP increased, consumption per unit of output for a mineral would increase, reach a maximum, and then decline. The data lying behind the Malenbaum hypothesis related to specific mineral commodities, such as copper or iron and steel, and his reported data covered a short span of time. In an earlier article, I (the senior author) explored the Malenbaum hypothesis. I concluded that a metal by metal analysis of intensity of use through time is most likely picking up substitution phenomena rather than fundamental tendencies phenomena rather than fundamental tendencies in the demand for total raw materials. This is illustrated clearly when one puts in juxtaposition the trends for aluminum and copper, and combines them in terms of relative weights. Further, the shift from goods to services is not necessarily a raw material saving shift. Thus, changes in the composition of GNP as per capita income rises may not be an adequate explanation for the inverted "U" posited by Malenbaum. I concluded my posited by Malenbaum. I concluded my examination of Malenbaum as follows:

" My preliminary work leads me to believe that the major phenomena that must be understood are the process of substitution and the relationship of materials demands to technological progress.
The Effect of Stimulation Methodologies on Production in the Jonah Field
Authors: Eberhard Mike , Mullen Mike
Published: December 2007

Improvements in stimulation technology have continued to increase our ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field, in Southwest Wyoming is a classic example of a reservoir that was commercialized with newer stimulation technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with reservoir permeability to gas less than 10 µD. Completion techniques have evolved over the years employing a variety of hydraulic fracturing techniques. In the past 2 years three techniques have emerged as the predominant completion methods: traditional nitrogen assist, induced stress diversion, and the use of flow thorough composite bridge plugs. This study evaluates the different techniques using spatial sampling to compare each well to its offsets and identify the completion scheme that yields the best results on cumulative production. From this study a clear best practice for completing wells in the Jonah field to maximize production was determined.