bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of a New Concept of Steerable PDC Bit for Directional Drilling
Authors: Roberts T. S.
Published: December 2007

This paper describes the development of a new range of Polycrystalline Diamond Compact (PDC) bits designed to have the smooth torque response of a roller cone bit but maintain the high penetration rates and long life achievable from a PDC bit. One such design features a 360° full contact gauge ring that prevents outer cutters from biting into the formation at gauge. This restriction to lateral movement reduces bit whirl and thereby increases cutting structure life. Thus because the bit drills more smoothly, torque fluctuations are lower resulting in a smoother bore hole which provides more predictable weight transfer. These advantages result in faster penetration rates when sliding because far less time is spent orienting the bit.

Laboratory tests utilized an instrumented sub to measure bit vibration as well as weight on bit (WOB), torque and revolutions per minute (RPM). The stability of several bit designs having identical cutting structures but varying degrees of junk slot enclosure was compared. The results show the use of enclosed junk slots significantly reduced bit vibration and gave a much smoother torque response.

Several case studies are presented that illustrate improvements in the most demanding directional wells. These bits have now been used successfully on many directional wells in the North Sea, United states and Middle East. Directional drillers have commented that these innovative bits give the directional response and low reactive torque of a rock bit but with three times the penetration rates.
Bit Balling Reduction by Electro-Osmosis While Drilling Shale Using a Model BHA (Bottom Hole Assembly)
Authors: Hariharan P.R. , Cooper G.A. , Hale A.H.
Published: December 2007

In this paper we present further work on the use of electro-osmosis to prevent bit-balling. Indentation tests in wet clay have indicated that the process of electro-osmosis (EO) becomes more efficient in clays with lower water content. This fundamental behavior of wet clay correlated well with coefficient of friction measurements under EO, between a rotating metallic cylinder and a stationary shale sample for different types of shales. Test results have demonstrated that shales with a higher water content >10%) respond to EO to a smaller degree compared to shales with lower water content (<10%). Furthermore, in clay/sand mixtures it was clearly seen that the process of EO became active when the clay content exceeded a threshold value of about 10–12% by weight. This finding indicates that EO may be effective in sand/clay mixtures whereas until the present it has been believed to be effective only in clays.

We have also conducted drilling studies using a model BHA (Bottom Hole Assembly) in which a stabilizer above the bit acts as the anode while the bit is cathodic. This self contained arrangement is preferred for practical application of the technology in deep wells. Drilling tests in Pierre shale using this equipment have shown increases in ROP (rate of penetration) of 30% in roller cone bits and up to 158% in the case of PDC bits when the bit was made negative, with substantially less cuttings adhering to the bit. The greatest increases in ROP were found at the higher weights on bit. The effects of EO increased progressively as the current density to the bit was increased.

P. 913
Revised Drilling Practices, VSS-MWD Tool Successfully Addresses Catastrophic Bit/Drillstring Vibrations
Authors: Shuttleworth N.E. , van Kerkoerle E.J. , Folmer D.R. , Foekema N.
Published: December 2007

To date, several wells have been drilled in the Friesland/Groningen area of northern Holland. Historically, catastrophic cutter damage/failure in the 12 1/4" Triassic section resulted in inconsistent and unacceptable bit performance. Here, the Triassic is an interbedded formation containing hard dolomite and anhydrite stringers and abrasive sands. The transition from a softer to harder formation at high inclination evidently initiated bit and drillstring vibrations, thus causing premature cutter failure of the PDC bits used in the program.

This paper presents a detailed analysis of the 12 1/4" section conducted after the drilling of Well No. 1. The recommendations arising from the study concentrated on the use of a real-time downhole vibration monitoring or VSSMWD tool (Vibration Stick Slip) in combination with revised drilling practices to reduce vibrations when encountering the interbedded formation. Thus, on Well No, 2, nearly all of the 2358-m Rijnland and the hard and abrasive Triassic forrntions were drilled with one PDC bit on a rotary assembly, where previously six bits were required. The authors will illustrate the benefits of a detailed interval analysis and discuss the role of the VSS system and the dring crew in addressing catastrophic drillstring and bit vibrations.

P. 925
Experience Acquired During Deep Water Drilling and Testing of 3 Explo/Appraisal Wells in the Girassol Field
Authors: Crepin Stephan , Ybert J.L. , Foulhoux Laurent , Payer Nicolas , Chassagne Alain
Published: December 2007

Producing oil in deep water is one of Elf's major challenges and goals for the next century.

Elf has drilled and tested successfully 3 exploration/appraisal wells in the Angola offshore - GIRASSOL field - below 1300 m of water. The first one was drilled with a DP rig (GIR 1), the other two, ("twinwells": GIR 2A & GIR 2B) with an anchored up-graded Semi-Submersible rig. The distance between the twin- wells was 90 meters allowing the opportunity to drill them with the same anchor pattern. The batch drilling of the riserless phases 36" and 26" had permitted the utilization of only one run for BOP and riser.

Our targeted reservoir on the GIR 2A was at a vertical depth of 2850 m. It was reached in a 12–1/4" diameter phase using an OBM. A 210 m core section of very unconsolidated sands from the zone of production on the first appraisal well was recovered. Also the well was flow tested at a very high rate of production through a cased holed 9–5/8" gravel-pack. Because of the location of the appraisal target on the second well, a 750 extended reached well in unconsolidated shaly and sandy formation was employed.

Anchoring and dis-anchoring operations have been very successful.

Meticulous inspection of the BOP by a third party specialist helped to prevent leaks and lost time. The failure of the ROV when spudding GIR 2A has pointed out the importance of some side services.

Because of the very poor Leak Off Tests of the surface formations the architecture of the well remained heavy in spite of not very deep targets. A tight monitoring of the mud weight has been important.

A drilling well head with weight set tools has been used.

P. 427
Producing Lease Operations - Design of Operating and Maintenance Jobs and Related Tools and Transportation Equipment
Authors: Kelly Harold S. , Filson Rogers C.
Published: December 2007

This paper reviews some of the economies achieved through methods work on lease producing operations and depicts some of the tools and special transportation units that were designed and put into service to improve the efficiency of the working force, lengthen the life of the lease equipment and reduce downtime lost production.

It was found that the old general classification of pumper with broad duties including pumping operations, equipment servicing, and minor repairs could be advantageously replaced with a pumper classification limited only to operating duties on a greater number of wells, plus a properly equipped tune-up and service mechanic whose time would be devoted 100 per cent to tuneup, servicing and preventive maintenance. This reorganization of lease operations resulted in lower total labor costs, longer life of equipment and less lost production from downtime.

The regular lease surface maintenance roustabout work is also subject to organization, special equipment, and transportation units which permit a reduction in the cost of maintenance labor and improvement in the maintenance of the leases.

Time and Methods studies of producing leases in several districts were used as a basis for designing operating and maintenance jobs and for determining labor requirements, tools and automotive units needed to more efficiently perform these jobs. Follow-up methods studies were made after the jobs, methods, tools, and automotive units had been redesigned to determine whether the planned savings had actually been effected.

This paper covers three broad categories of work as they were delineated by the methods studies; namely (1) Operations, (2) Tune-up and Preventive Maintenance, and (3) Field Maintenance and Repair.
Economic and Technical Features of a Revolutionary Chemical Scale Inhibitor Delivery Method for Fractured and Gravel Packed Wells: Comparative Analysis of Onshore and Offshore Subsea Applications
Authors: Webb P.J.C. , Nistad T.A. , Knapstad B. , Ravenscroft P.D. , Collins I.R.
Published: December 2007

The deposition of scale, such as carbonates and sulphates, in production facilities represents a serious operational problem that can result in significant well productivity decline. Currently implemented scale control strategies can involve significant capital and operational expenditure.

Development work, involving laboratory testing and a field trial, has demonstrated the technical benefits of a revolutionary method of downhole scale inhibitor delivery. Economic analysis indicates that significant benefits can be derived for a variety of field development and well completion types. The greatest economic benefits would be realized for subsea and minimum facility installations with high intervention costs, where squeeze delivery of scale inhibitor or mechanical workover are used for scale control. In addition, major economic benefits can be realized for horizontal wells with unfavourable pressure regimes, multi- lateral type completions, multiple fractured wells, and many conventional completion types.

The new chemical delivery method offers cost reduction through reduced deferred oil, efficiency of chemical usage, and elimination of coil tubing and intervention vessel use. Economic analysis has indicated that fracturing a well and deploying proppant impregnated with scale inhibitor, is economically preferable to a strategy of squeeze treatment for some conventionally unfractured wells with high intervention costs, for example subsea wells.

An additional economic benefit of proppant impregnated with scale inhibitor (Chemflow) is increased well productivity. The benefit is derived from the combined effect of improved gel breaking, and scale inhibition during well clean-up. This has been demonstrated in laboratory testing and would appear to be confirmed by field observations.

A further benefit of applying scale inhibitor as chemically impregnated proppant is the instantaneous treatment of produced water when water breakthrough occurs. This feature avoids the formation damage that can occur before squeeze treatment mobilization. In addition, for some applications involving large fractures there is the potential for lifetime well treatment.

P. 323
Use of Perforation Tunnel Permeability as a Means of Assessing Cased Hole Gravelpack Performance
Authors: Burton Robert C.
Published: December 2007

This paper proposes a new method for comparing the effectiveness of cased hole gravelpacks. The new method employs effective perforation tunnel permeability as the primary indicator of gravelpack effectiveness.

Completion pressure losses in cased hole gravelpacked wells are subdivided into categories and systematically reviewed to show the relative importance of alternative design features. From this information, perforation tunnel permeability is shown to be the major determinant of completion skin and flow efficiency in cased hole gravelpacked wells. The technique is shown to be useful in both low velocity (Darcy) and high velocity (non-Darcy) flowregimes.

Field examples are used to show how this technique can be used to diagnose design flaws and improve well performance results. These examples show that effective perforation tunnel permeabilities in cased hole gravelpacked wells are significantly lower than surface measured gravel permeabilities. This has important implications for well design and remedial candidate selection.

P. 359
Effect of Sand-Grain Size on Perforator Performance
Authors: Brooks J.E. , Yang W. , Behrmann L.A.
Published: December 2007

A rock's compressive strength is generally recognized to be key in determining the depth of penetration for shaped-charge perforators, both for downhole formation rock as well as for artificial rock such as concrete. What is not recognized is that the size, distribution and hardness of the composite sand grain of the rock are also important parameters in determining penetration. Depending on the size of the grain, experiments show that penetration depth can be significantly affected, with penetration in coarse-grain-sands considerably reduced from that in fine-grain sands.

We present experimental results of penetration depths in concrete targets made with a wide range of sand-grain sizes, from very fine to very coarse, Results show that penetration in concrete targets made with single-size sands (very fine to gravel size) can have a range of effect of about 250%. Also included in the data set are tests made with API RP43 Section 1 targets using sands that are within the specification size but at opposite ends of the allowed tolerance. The data show a difference of at least 10% in penetration between these two limits, Finally, we discuss the practical implications of these results as regards API Section 1 testing and the expected effect on downhole rock penetration.

P. 371
Methodology of Fluid Leakoff Analysis in High-Permeability Fracturing
Authors: Ispas I.N. , Britt L.K. , Tiab D. , Valko P. , Economides M.J.
Published: December 2007

Hydraulic fracturing in medium and high-permeability reservoirs differs significantly from conventional fracturing, since the optimal placement of proppant requires shorter and wider fractures. The optimal fracture dimensions are achieved by executing a tip screenout design technique. Successful application of this technique assumes realistic description of the fluid leakoff process. Fracture calibration treatments (minifracs) have been used to identify leakoff characteristics. In addition to the application of data obtained from such tests (i.e. incorporation into the fracture job design) an increasingly important use is to obtain reservoir engineering parameters, such as formation permeability.

This paper is based on two methods, used for the determination of the leakoff parameters from the pressure fall-off stage of a calibration treatment. The first method is the well known technology, which we have called the Nolte-Shlyapobersky method to determine an overall leakoff coefficient. The second method is a modified form of the Mayerhofer et al technique, which attempts to de-couple the two main elements of the leakoff process: the filtercake resistance and the transient flow in the formation. For other methods concentrating more on the pressure fall-off after the fracture closes see References 3 and 5.

Field examples will be used to demonstrate the basic steps of the presented methodology. Emphasis is on limitations and possible pitfalls with suggested remedies. A detailed sensitivity analysis is presented which underlines the data quality required to determine reservoir and treatment parameters with any accuracy.

P. 493
A Coulpled Wellbore-Hydraulic Fracture Simulator for Rigorous Analysis of Frac-Pack Applications
Authors: Sherlock-Wills Terri , Romero Jean , Rajan Surya
Published: December 2007

A Coupled Wellbore-Hydraulic Fracture Simulator for Rigorous Analysis of Frac-Pack Applications

Frac pack stimulations have been used extensively to provide a combined treatment for well stimulation and sand control. It has been observed that treatment failure in such operations is often caused by a premature wellbore screen out. However, until now the design and evaluation of such treatments have been performed solely using fracture simulators that neglect the effect of the wellbore hardware (crossover ports, blank, screen, washpipe, etc.) on the treatment.

In an effort to address this limitation, a wellbore simulator was coupled with a fracture simulator to provide the capabilities of predicting, and subsequently eliminating, such occurrences. The fracture simulator calculates the fracturing parameters such as proppant distribution in the fracture, fracture height, and two-dimensional fluid flow. These parameters provide the boundary conditions for the wellbore simulator. Additionally, the fracture simulator was enhanced to correctly simulate fluid leakoff and tip screen out designs in high permeability formations.

The fluid and proppant flow around the screen is calculated using a pseudo three-dimensional wellbore simulator which provides a complete design and evaluation tool of frac pack treatment. The effects of a deviated wellbore, proppant bridging around the screen, proppant settling in the wellbore, and fluid flow through the screen are taken into account; in addition, the coupled simulator can model an induced wellbore screenout at the end of the treatment either due to a deliberate reduction of the injection rate or the shifting of the tool to the circulating position.

This paper shows a field example using this coupled simulator to evaluate a frac pack treatment that was terminated due to a premature screen out. The calibration test is initially analyzed following which the frac pack treatment is simulated and compared with field measurements.

P. 505
Damage Characterization and Production Optimization of the Hassi-Messaoud Field, Algeria
Authors: Allouti A. , Ziada A. , Ramses W. , Fragachan F.E.
Published: December 2007

The Hassi-Messaoud Field is a thick sandstone reservoir covering an area of 2000 km2. It is a flattened anticline located on the north of the El-Biod-Hassi-Messaoud elevation. This elevation is formed by a sequence of horsts and grabens contained by faults in a submeridien direction. The faults are in general SSW to NNE oriented and cross all the producing reservoir (Cambro-dovicien).

The producing reservoir is located at 3300 m and consists of four distinct formations in addition to a "zone d'alterance"(transition zone). These are subdivided into drains (producing intervals) characterized by distinct properties. Overall, the field is divided into 25 separate zones that differs in their geological and petrophysical properties and are under pressure maintenance by means of water and/or gas injection. Fig. 1 shows the field different zones and a cross section of the Cambro-Ordovicien formation.

This paper presents the successful application of a methodology to optimize production and results of matrix acidizing treatments in the Hassi-Messaoud field. The corner stone of the methodology is damage characterization. The damage is analyzed and evaluated per zone. Categories according to damage severity and frequency are presented. Among others these categories include salt deposition; scales deposition including barium sulfate, clays types, fines migration, and asphaltenes. A thorough coverage of the geology, mineralogy, petrophysical properties, formation fluids characteristics, reservoir pressure evolution and pressure maintenance, wells completions and production schemes are presented for the 25 different zones that integrate the heterogeneous Hassi-Messaoud field.

Finally, production optimization as a result of applying the methodology on matrix acidizing treatment is presented and quantified by :treatments success ratio;production gain;payout time;decline rates of wells before and after treatment andactual cost per ton of production gained.

P. 549
The Effect of the Thermal Stress on Wellbore Stability
Authors: Tang Lin , Luo Pinya
Published: December 2007

The thermal stress near the wellbore occurs because the temperature near the wellbore is changed by mud in well. The stress distribution near the wellbore is changed by the thermal stress, Eventually, the wellbore stability is affected. So, in this paper, first the integral equations of the thermal stress caused by varied temperature near the wellbore are derived from the thermoelastic theory. Then, the numerical computation is conducted for the thermal stress equations with the numerical results simulated for the temperature field near the hole. The plots of radius thermal stress distribution is obtained as a function of time. Further, the thermal stress is stacked with the pure mechanical stress near wellbore. Finally, the effect of the thermal stress on the wellbore stability is analyzed by use of the Mohr-Coulumb criterion for the any drilling condition and any time. The simulated result shows that the tangential and axial thermal stress on the holel formation interface may make the total effective stress to decrease on it below some point of section, and make the total effective stress to increase up some point. It is an important influence on the stress distribution near the wellbore. Therefore, the theories and simulated results in this paper have a guiding signification for the wellbore stability in the high temperature well and for the recovery of the production, such as the fracturing, injection, and thermal production.

P. 85
The Fracturing Technique to Limit Hydraulic Fracture Height Growth Put into Effect
Authors: Liu Shuzhi , Ren Shuquan , Zhao Jinzhou , Yang Liangxian , Wang Qingxiang , Chen Shu
Published: December 2007

In the paper, a three dimensional fracture propagation model was first established, then the factors that affect the fracture vertical growth were analyzed by means of the fracturing design software from the model. It is shown that although many factors influence the fracture height growth, the most important one is the minimum in-situ stress contrast between payzone and bounding zones. The pump rate and rheologic parameters for fracturing fluid also affect the height propagation to some extent. By analyzing the three dimensional fracture propagation model, we found that it is the stress intensity factors on the tips of line crack that have a direct influence on the height growth. Consequently, even though it is not easy to increase the in-situ stress contrast, we can manage to change the vertical distribution of flowing pressure in the fracture by adding some buoyant and sedimentary material to pad fluid, forming two artificial barriers at the top and bottom of the fracture. The two barriers decrease the flowing pressure in the fracture located at bounding zones, which is equivalent to the increase in in-situ stress contrast. Up to now, 13 wells have been fractured by optimizing treatment parameters and adding barrier material. All the wells had a great increase in oil production, and the fracture height inferred from well temperature logging is close to the perforated interval.

P. 165
Water Breakthrough Numerical Simulation in Fractured Gas Reservoirs
Authors: Zhang Lie Hui , Feng Yi Yong
Published: December 2007

In the SiChuan gas fields of China, because of the complex geologic conditions, almost all the active water invasions appear to be water breakthrough along fractures. These seal the path of gas flowing in fractured gas reservoirs, as a result largely reducing the efficiency of gas production. Currently, it is very difficult to simulate such fracture water breakthrough using known fracture models (e.g, dual porosity, single permeability and dual porosity, dual permeability).

In this paper, we established a fracture water breakthrough numerical simulation model of water drive gas reservoir after we extensively investigated typical water breakthrough in SiChuan gas fields. Next, we applied this model to simulate the bottom water gas field of WeiYuan of SiChuan province and suggested effective water preventing measures. Then we gave four kinds of water invasion models: slow water coning, vertical water breakthrough, horizontal water breakthrough, vertical water breakthrough and horizontal breakthrough. Our simulation increased our knowledge of the mechanism of water invasion. Our models have been widely used in gas production in SiChuan fractured gas reservoirs.

P. 437
Improving Recovery through Peripheral Waterflood Management in Multilayered
Authors: Mamgai D.C. , Singh Lehmbar , Rangaraj S. , Singh Daljit
Published: December 2007

One of the Eocene age fields in Cambay Basin of India, having about 1000 MMbbls of initial oil implace, has got nine reservoirs of thickness varying from 14 ft to 66 ft. Two main multilayered reservoirs are being produced under peripheral water flood from early stage of exploitation. The estimated oil implace of these two reservoirs is 560 MMbbls and 170 MMbbls and expected ultimate recovery is 55 percent and 61 percent respectively. while about 82 percent of recoverable oil from these two reservoirs has been already recovered their present rate of production is 5200 BOPD with 72 percent of water.

Drilling of a few new wells for EOR, in the area that was expected to be flooded by encroaching injected water in the said two reservoirs has shown virgin oil saturation. On this basis, study of movement of advancing flood front in past - dynamic model, mapping of heterogeneity distribution pattern static model and, calculation of natural water influx and voidage have been taken up. Integration of these studies along with recovery analysis and cased hole carbon oxygen logging have been used in identifying areas of bypassed oil. The waterflood management by shift of injection row, regulation of injection rate and selective injection in low permeable layers in different flow regimes has been found to be effective in exploiting bypassed oil and improving sweep efficiency, in turn enhancing recovery and increasing oil production. Implementation of study in field has resulted in an increase in oil production form 1400 BOPD to 2000 BOPD from one sand.

The field has already produced 46.7 percent of total inplace oil in the last 35 years. The economic life the field will get extended by exploitation of bypassed oil and improvement in sweep efficiency through effective surveillance of water flood. P. 727
Journey From Well Logs/Cores to Integrated Geological and Petrophysical Properties
Authors: Bahar Asnul , Kelkar Mohan
Published: December 2007

Reservoir studies performed in the industry are currently moving towards an integrated approach. Most data available for this purpose are mainly from well cores and/or well logs. The translation of these data into the petrophysical properties, i.e., porosity and permeability, at interwell locations that are consistent with the underlying geological description is a critical process. This paper presents a methodology that can be used to achieve this goal. The method is validated through a field application.

The framework developed in this work starts with the given geological interpretation, i.e., facies and petrophysical properties, at well location. A new technique in evaluating the horizontal spatial relationship is provided. The technique uses the average properties of the vertical data to infer the low frequency characteristics of the horizontal data. Additionally, a correction in calculating indicator variogram, which is used to capture the facies' spatial relationship, is provided.

A new co-simulation technique to efficiently generate petrophysical properties consistent with the underlying geological description is also developed. The technique uses the conditional simulation tools of geostatistical methodology and has been successfully validated using the field data (sandstone and carbonate fields). The simulated geological descriptions matched well with the geologists' interpretation. All of these techniques are combined into a single user- friendly computer software that works on the PC platform.

P. 543
Defining Business Critical Workflows for Integrated Reservoir Optimization
Authors: Trayner P.M.
Published: December 2007

People remain Exploration and Production (E & P) companies' biggest asset, and yet, many studies show that, as an industry, we have struggled to harness the skills and knowledge of highly qualified professional staff in the critical business decisions needed in today's demanding environment.

The concepts of "Business Critical Workflow" and "Interpretation Cycle Time" will be shown to be crucial factors holding back our business. These represent the time it takes to design, collect, prepare, understand and take decisions from data, one of our other biggest assets. Today, this workflow is all too often a slow, inefficient and discontinuous process, and high risk business decisions are frequently taken without full recourse to all the available data, and more importantly to the knowledge derived from these data.

One of our key challenges is to align the business objectives of the various components of a typical E & P organization and to ensure that each of these components adds value throughout the E&P cycle. Thus we need to build a shared earth model for our oil and gas field prospects, which can be enhanced and used by all members of our business team, whether they are geologists, drillers, production engineers, geophysicists, economists or business managers. By reducing the time and effort needed to build, maintain and continuously update these models, the "Knowledge base" from our professional staff can be fully integrated and better utilized.

The generic use of modern software technologies will be illustrated with reference to several typical workflow scenarios. The adoption of industry standards will continue to be a key factor in the growth of such solutions, and in the future, E&P companies should have the opportunity to assemble applications from different vendors, without the need for time consuming data transfers from one platform to another. Standards will also bring a common application "look and feel" to users, irrespective of the data domain or application vendor, and such initiatives will help to reduce the learning curve for new or re-trained users. Vendors will undoubtedly continue to focus on ease of sue issues in their software development, but it will always be necessary for Oil companies to make the proper commitment in terms of relevant training and support infrastructure for the true (and significant) returns on investment to be realized.

P. 627
Techno-Economic and Risk Evaluation of an EOR Project
Authors: Joshi Sameer , Castanier Louis M. , Brigham William E.
Published: December 2007

The terms uncertainty and risk are never far off in the analysis of an exploration prospect or an oilfield investment project. Risk arises because there is uncertainty about the course of future events. Monte-Carlo simulation can be used to quantify risk. This process consists of treating uncertain input parameters of a problem as stochastic variables. All valid combinations of these input parameters are then tried, to simulate all possible outcomes. This results in specification of the model output as a statistical distribution of probable values.

The specific oilfield to which this analysis was applied is the Wilmington steamflood project previously operated by Union Pacific Resources (UPRC) at Long Beach, California. The methodology used is general and can be applied to any project which has uncertain input parameters. The software used will easily run on personal computers (PC's) and is available as an add-in program for a commonly used spreadsheet program for PC's.

Oil production rates for the steamflood had been predicted by using Ramey's generalization of Marx and Langenheim's method (SPE 29669). An economic analysis of the steamflood was carried Out using capital budgeting and discounted cash flow techniques. Monte-Carlo simulation was done for both the production rate calculations as well as the economic analysis. A statistical analysis of the oil production calculations and economic analysis was carried out, which also proved to be a sensitive method for checking the convergence of the Monte-Carlo simulation.

The simulation output consisted of probability distributions of produced oil volume, yearly cash flows, net present value (NPV) and internal rate of return (IRR) for the project.

P. 633
New Guidelines for Applying Curable Resin-Coated Proppants
Authors: Nguyen P.D. , Dusterhoft R.G. , Dewprashad B.T. , Weaver J.D.
Published: December 2007

Failures of resin-coated proppants have been primarily attributed to incompatibility between fluid chemistry and the resin, insufficient closure stress, the practice of flowing the well back too aggressively, or stress cycling. This paper describes the failure mechanism that may be more predominant than any of the others: curing too fast. Proppant consolidation kinetics were studied with the use of differential scanning calorimetry and compressive-strength development. Additional studies to determine ultimate compressive-strength development and the effects of flow erosion and stress cycling on resin-coated proppants were performed. This study has determined that the temperature profile and time before proppant grains are compacted and closure stress during curing are critical factors affecting consolidation properties. The investigation also resulted in the identification of the appropriate resin-coated proppants and guidelines for their uses in proppant flowback control in hard-rock fracturing and in sand control of soft formations as in screenless fracpack completions.

P. 587
Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formations
Authors: Buijse M.A. , van Domelen M.S.
Published: December 2007

M.A. Buijse, and M.S. van Domelen, SPE, Halliburton B.V

Historically, emulsified acids have primarily been used in fracture acidising. By combining information from theoretical studies, experimental studies and field testing, a better understanding has recently been gained of the application of emulsified acids in matrix acidising. This paper discusses the use of emulsified acid as a stimulation fluid for matrix treatments in heterogeneous carbonate formations.

Theoretical and experimental studies published on the acid wormholing process in carbonate formations have shown the efficiency of systems that have low diffusion rates, for example acid-in-oil emulsion systems. Emulsified acid is especially effective when the injection rate is low, such as in low permeability formations or damaged formations. In these cases, plain HCl acid will spend on the formation face and will not create wormholes that penetrate deep into the formation. At comparable injection rates, emulsified acid is capable of forming deeply penetrating wormholes and efficiently stimulates the formation.

In this paper, results of flow tests are presented which compare the efficiency of emulsified acid with that of plain HCl acid. Several emulsified acid systems were tested. The effects of the injection rate, viscosity and acid/oil volume ratio were analyzed on core samples. Rheological properties and temperature stability (up to 250 F) of the emulsion systems were analyzed by means of Fann-50 tests.

Acid-in-oil emulsions are effective stimulation fluids in large intervals where streaks of high-permeability can act as thief zones. This is shown by means of example calculations of the fluid flow and distribution in a well.

Practical and economical aspects of mixing and pumping emulsified acid in the field will be discussed. Characteristics of candidate formations will be summarized and rules-of-thumb for preliminary treatment design will be presented.

P. 601
System Identification Approach to Watercut Analysis in Waterflooded Layered
Authors: Renard G. , Dembele D. , Lessi J. , Mari J.L.
Published: December 2007

Oil recovery in layered reservoirs within a complex geological structure is very often lower than expected. This is due both to the uncertainty in assessing hydraulic continuity between wells and to the trapping of oil in some unswept layers or field areas.

The symptoms of such a situation, for a well with commingled production from separate layers inequally waterflooded, may be erratic watercut variations. Such variations may be the result of interferences from surrounding injection and production wells that create changes in rate distribution between the various layers.

The objective of this paper is to present a new methodology to model the watercut of a producer as the response of a linear system using neighbouring well rates as inputs. The methodology based on a system identification approach implies the following steps: filtering of the raw data, selection of input wells by a technique of Main Component Analysis, identification of model coefficients by fitting the watercut of the modelled well over a restricted period of production, validation of the identified model and finally evaluation of the proper contribution of each input well.

The methodology has been applied to actual data from an area of the Arlan field in Russia. Models obtained were able to successfully forecast the watercut variations of most of the production wells over a several months period. It was then possible to use the geological model of the field area for interpreting these models in terms of main interactions between wells and sweep efficiency for each layer.

As shown in the paper, the proposed methodology has the potential (I) to define main hydraulic communications between wells, (II) to give a diagnosis on oil and water saturations of the different pay zones for a commingled producing well and (III) more generally to provide a predictive tool for the interpretation and improvement of the sweeping in layered reservoirs.

P. 35
Overview of Field Results Using TTBP as Effective Water Shut-Off Treatment In
Authors: Mohammed M.A. , Al-Mubarak M.A. , Al-Mulhim A.K. , Al-Mubarak S.M. , Al-Safi A.A.
Published: December 2007

Water shut-off treatments (WSOT) are routinely performed on wells in the carbonate formation, in one of Saudi Aramco's oil fields that are dead, have high water cut, or low-flowing wellhead pressure. WSOT using through-tubing bridge plugs (TTBT) in both open-hole and cased-hole completions have been employed. Such a treatment was successfully applied in zones that are 100% swept by the water flooding and are no longer contributing oil and in high permeability zones (super- K) located in the lower interval. These wells were then activated and have been placed on production. The field results from 40 bottom water shut-off jobs, using TTBP technique, are presented. The 1990-1996 water shut-off jobs added a total of 88.0 MBD of producible potential. In addition, the application of TTBP method increased recoverable reserves and avoided expensive workover costs.

This paper presents data to show that TTBP technique is very effective compared to other methods of water shut-off jobs. Significant cost reductions are realized. The success ratio of this treatment in the open-hole completion (OH) can be as high as the cased-hole (CH) completion, provided that a gauge' hole exists.

P. 147
Pore Scale Gravity Drainage under Different Wettabilities and Multiphase Coexistence
Authors: Saputelli Luigi A. , Dawe Richard , Grattoni Carlos
Published: December 2007

Improving the hydrocarbon recoveries for reserves is actually regarding new technologies and better porous media understanding. However, there is still a long way to go to improve efficiency, as many challenges remain. The arrangement and movement of three phases within the pore spaces are complex processes to model and comprehend.

In the porous medium, coexisting fluids with different densities are redistributed vertically by the force of gravity. Gravitational forces counteract with capillary and viscous forces; vertical barriers may also reduce gravitational performance as well. These divert forces often cause poor gravity segregation performance, leading to the trapping of the lighter phase fluid and consequent low hydrocarbon recoveries. Gravity forces play an important role in determining initial fluid distribution and at all stages of hydrocarbon reservoir development.

This project focuses on examining gravity effects that compete with capillary forces, under different scenarios of wettabilities, density differences, low interfacial tension differences and multi-phase coexistence. The objectives of the study are to understand physical interactions, the impact on oil recovery and to determine when they are important.

The physics of the processes surrounding gravity forces and their interaction with other reservoir parameters were thoroughly studied. In a three-phase system, it is seen that for the same positive spreading coefficient, the oil recovery kinetics is different and that gravity drainage is much less efficient in the oil-wet system, than in the water-wet. In oil- wet porous media, oil recovery by gravity drainage is independent of the spreading conditions. The Bond Number is appropriately corrected as a function of wettability and fluid saturation. Some corrections are pointed out in order to achieve proper modeling of reservoir fluid capabilities in the presence of gravity terms.

P. 179
Compositional and Relative Permeability Hysteresis Effects on Near-Miscible WAG
Authors: Christensen J.R. , Stenby E.H. , Skauge A.
Published: December 2007

Evaluation of compositional effects and fluid flow description on near-miscible (water-alternating-gas) WAG modeling have been studied for a North Sea oil field starting production in 1998. A sector model with four wells was applied to simulate a heterogeneous sandstone reservoir, and a compositional model was used to compare different production strategies e.g. waterflooding and a near-miscible (WAG) injection. In the WAG scheme both dry and wet (rich) hydrocarbon gases have been considered for injection. The phase behaviour was quantified by comparing the performance of the different injection gases.

Result obtained shows the WAG injection gives improved recovery compared to water injection, due to better sweep and lower residual oil saturation. Simulations with and without relative permeability hysteresis (two-phase model) were compared. The effect of trapped gas on oil recovery does not seem significant with the compositional model. The WAG process has been optimized with respect to slug size and the water-gas ratio.

A black-oil-model was generated tuned to fit the results from the compositional simulations. A WAG three-phase relative permeability hysteresis model using cycle dependent relative permeabilities for both wetting and non-wetting phases, have been compared to the standard two-phase Killough and Carlson hysteresis models. The results show significant lower gas ratio and a higher oil recovery for the WAG injection when using cycle dependent relative permeabilities.

The simulations show sensitivity toward the three-phase model whereas Carlsen/Killough type hysteresis has little/no influence on the oil recovery.

Simulations indicates that the recovery by WAG-injection may be underestimated in the compositional model due to lack of possibility for cycle dependent relative permeability hysteresis, whereas the black oil model underestimates the phase behaviour effect. The results indicate that the WAG- injection might have an upside potential with respect to the influence of combined phase behaviour and relative permeability effects.

P. 233
Use of Full-Field Simulation to Design a Miscible CO2 Flood
Authors: Brinkman F.P. , Kane T.V. , McCullough R.R. , Miertschin J.W.
Published: December 2007

A study using full-field reservoir modeling optimized the design of a miscible CO2 flood project for the Sharon Ridge Canyon Unit. The study began with extensive data gathering in the field and building a full-field 3D geologic model. A full-field simulation model with relatively coarse gridding was subsequently built and used to history match the waterflood. This waterflood model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. Predictions for the CO2 flood used an in-house 4-component simulator (stock tank: oil, solution gas, water, CO2). A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood.

P. 265
Experimental Foundation for Relative Permeability Modeling of Foam
Authors: Vassenden F. , Holt T.
Published: December 2007

Optimization of foam treatments requires modeling or simulation of the process using a foam model that is capable of reproducing the critical properties of foam. The present work present a simple model that is based on the relative permeability concept, and is well suited for simulation of foam processes with conventional or slightly modified numerical simulators. The model can unify the understanding of a number of phenomena that characterizes foam flow. The validity of the model is substantiated by experimental data.

A consistent interpretation of foam breakdown, shear thinning effects, permeability effects, and effects of system pressure is possible with the presented model for gas relative permeability in a foam.

P. 73
Incorporating Seismic Attribute Porosity into a Flow Model of the Grayburg Reservoir
Authors: Weinbrandt R.M. , Trentham Robert C. , Robinson William
Published: December 2007

The Grayburg reservoir of the Foster - South Cowden field has been produced since 1938 and water-flooded since 1962. Production had declined to near abandonment level at the start of this project. The initial approach to construction of the flow model was conventional. Logs and cores provided the basis for a geological model. Production data was assembled and validated as were the few measured pressures taken early in the fields history. Production testing of all wells was initiated with new equipment to provide accurate current production data. Pressure transient testing of all wells was initiated to provide accurate current pressures. History matching pressures and water cuts validated the flow model and the flow model has since guided field operation, subject to the limits imposed by the spacing of the well data which was one reliable well log per 32 acres of reservoir. At this scale compartmentalization, heterogenialy, of the reservoir was obvious, requiring the use of 3-D seismic to define porosity in the area between wells.

The 3-D seismic data set was reprocessed to retain high frequencies, thereby improving vertical resolution to the range of 50 feet. Seismic traces sample areas are 110 by 110 feet (bin size). Seismic inversion model traces exhibit a high degree of correlation to the well log data and a correlation was developed between seismic velocities and porosity for each geologic zone. The correlation was used to develop porosity maps for each zone used in the flow model. The resulting flow model was validated through the history matching process and used to guide the redevelopment of the waterflood.

P. 115