bluuebunny/crossref_metadata_2025 huggingface dataset:
A Management Technique That Integrates And Glues Cost And Environmental Performance Targets In E&P Drilling
Authors: Paulsen J. E. , Jensen B. , Pettersen J. , Svensen T.
Published: December 2007

This paper presents an integrated management technique that has been employed with success over the last 8 years in Statoil operations offshore Norway. The technique has been applied in integrated management of drilling fluids and drilling waste and is particularly suited for this purpose. It is argued that the attractive feature of the technique; the successful linking of tailor made technology employment and cost efficient environmental performance criteria have a much wider application potential. The fundamentals of the management concept are presented and data and examples are provided to highlight the structural constrains to be solved and the effect of the management technique applied.

The technique involves the supplier chain from procurement and through the life cycle of the operations. Performance criteria are linked to the concept of using best available techniques (BAT) to deliver the service. The responsibility of fluid providers is extended to include waste minimization; to be accountable for waste accrued by use of their products.

Experience and results since implementation show dramatic improvements in both cost savings and environmental performance for both operator and the fluid providers.

The effect of the management technique can be impressive as presented in this case where recycling of drilling fluids was increased by several orders of magnitude, drilling waste was significantly reduced and cost savings of several hundred MNOK (1US $ = 6.2 NOK) over a period of 8 years were measured. A change in attitude and awareness among the suppliers has been apparent, advances in technology that support sustainable industry practice in drilling has now become an important competitive edge. The management technique is argued to be superior to previous management techniques with respect to capacity to integrate and resolve multi criteria challenges.
Frontier HP/HT Exploration Drilling in the Krishna Godavari Basin, India
Authors: Kumar Suresh , Klimentos Theodore , Affes Sami
Published: December 2007

This paper describes a holistic approach to drilling engineering employed to design and drill the deepest offshore well in India. The paper covers the well construction methodology in conjunction with the contracting strategy and Service Quality Management processes. Moreover, the paper presents an innovative formation evaluation technique using wireline logs at HPHT conditions to optimize the perforation strategy and perforation depth interval selection in the absence of resistivity log data. Furthermore, borehole stability related problems were evaluated and a Mechanical Earth Model developed to improve the drilling performance in this area. The paper describes the application of the model in the exploration wildcat environment. The material presented will facilitate other well construction teams facing challenging drilling objectives in such a hostile remote environment. The paper also highlights the data acquisition challenges in the HTHP environment (410 deg F BHST and 12,000 psi BHP).
Innovative Advanced Technologies Overcome Directional Drilling Challenges of S and J Type Wells in N. America and Canada
Authors: Janwadkar Sandeep , Belavadi Mukund , Fortenberry David , Dawkins Brett , Kramer Mark , Privott Steve , Rogers Tom
Published: December 2007

The Barnett Shale field presents numerous drilling challenges. Meeting the increasing demands of natural gas requires economical development by efficient drilling of directional and horizontal wells. The standard technique for drilling S and J type directional wells was by utilizing steerable motors. This technique has several drawbacks: frequent trips to change angle of the AKO for the build/tangent/drop sections, poor hole quality due to string rotation, drillstring/BHA/casing wear, excessive cement volumes due to hole enlargements and high torque and drag due to wellbore tortuosity. Frequently the wells drilled in this field are closely spaced which require precise control of the well path to prevent collision. Steerable motors generate high wellbore tortuosity as corrections to the well path are made after every survey. Automated rib steering systems with rotating drill strings are cost prohibitive for this application.

To overcome these drilling challenges a strategy was outlined that comprised of the new non-rotating automated rib-steering system for low inclined 3-D wellbores. Research, field tests and application of innovative and sophisticated technologies has resulted in the development of this state of the art directional drilling system.

Since the introduction of the new technology many wells have been drilled in various fields of N. Texas and Canada with a build/drop rate up to 3°/100 ft. All sections of the wellbore (vertical, build, turn, tangent and drop) were performed without having to trip. Inclination of the tangent sections was maintained within +/- 0.2° of the target. Azimuth corrections were made without interrupting the drilling process and all directional operations were carried out by the system's automatic closed loop control. The new system has minimized hole enlargements, reduced torque/drag helping deliver a smooth, high quality wellbore and increased efficiency and quality of cementing operations. This has allowed the operator to log and set tubulars without incident and maximize the productivity from this field.

This innovative directional drilling system can be utilized to drill ‘S’ and ‘J’ type directional wells without string rotation, low-inclination convoluted well profiles can be drilled with precision due to constant control over inclination and azimuth. Different sections of the well are drilled without tripping by the systems closed loop control.
Cementing Under Pressure in Well Kill Operations: A Case History From the Eastern Mediterranean Sea
Authors: Johnstone Kristian , Conlon Tom , Gill Alex , Bahr Mahdy , Waheed Arshad
Published: December 2007

Well control can be an unpleasant experience. In its initial stages the problem often appears unconquerable and weeks can pass without progress.

This paper is about the successful abandonment of such an episode of well control, in deepwater (i.e. greater than 300 m water depth), that was initially suspended with a closed-in subsea BOP. The BOP held in place a sheared 5-in. drillpipe that had been intermittently blowing dry gas and formation cuttings to the rig floor for 20 days.

The objective of the well-recovery operations was to re-enter the well and properly abandon it without creating another uncontrolled situation. All operations were to be conducted in compliance with HSE protocols.

It was paramount to have total control of the well at all times necessitating two BOP stacks. This contingency resulted in the suspension of a heavy load on the seabed, subject to excessive bending moments during bad weather. The well head arrangement was essential but the time loss caused by weather conditions was becoming intolerable. New and innovative plans made during the well-control operations cut 3 to 4 weeks of uninterrupted operation down to 5 days of operation. Cementing under pressure was the key abandoning solution. Several scenarios were drawn up for this eventuality and this paper elaborates on the decisions, choices, and solutions made during the final abandonment operation.
A New Analytical Model for the SAGD Production Phase
Authors: Nukhaev M. , Pimenov V. , Shandrygin A. , Tertychnyi V.
Published: December 2007

Steam chamber (SC) control during steam-assisted gravity drainage (SAGD) has a great impact on the efficiency of heavy oil and natural bitumen recovery. An optimal production rate and corresponding bottomhole temperature and pressure should be maintained to improve SAGD cumulative oil recovery and the steam-oil ratio.

SAGD optimization work includes simulation results and real-time data monitoring. Existing analytical models1,2 are mainly dedicated to describing the ability of a reservoir to drain heated oil and do not depict all details of real SAGD processes.

In the present work a new analytical model of the SAGD production regime is described. The initial stage of oil production is considered before SC reaches the production well. The model accounts for mass and heat transfer during the process of heavy oil recovery and establishes a significant correlation between production rate and the dynamic of SC evolution. The model that was developed was compared with simulation done by commercial reservoir simulation software.
Improved BHA Sag Correction and Uncertainty Evaluation Brings Value to Wellbore Placement
Authors: Studer R. , Macresy L.
Published: December 2007

Recent well positioning uncertainties evaluation per SPE published ISCWSA model for MWD survey tools suggests that 80% of the inclination measurement error budget is a consequence of BHA sag.

BHA sag is the misalignment of the directional sensor with the borehole direction due to deflection of the MWD drill collar under gravity and borehole curvature. The magnitude of the error depends on BHA type and geometry, sensor spacing, hole size and several other factors.

This paper presents a new methodology based on modern 3D BHA/Hole interacting modeling for BHA sag corrections and residual error evaluation at each MWD survey stations.

11 different typical 17½" and 12¼" rotary and steerable motor BHA's with variable gauge stabilizers were computed in multiple configurations (borehole geometry, BHA settings, friction…) following a Monte Carlo process which involved more than a million simulations. Results of this study show that the residual BHA sag uncertainty as proposed by the ISCWSA model can be further reduced by as much as 50%.

A simplified software automated process was developed in order that Operations Support Centres can easily integrate the proposed methodology as part of near real time Survey Management advanced processing routines.

A sound BHA sag correction method along with a thoroughly analysed residual sag error, readily fit for use within the ISCWSA MWD well positioning uncertainty model (today's industry standard), appears essential in a wide variety of directional drilling applications including extended reach and horizontal drilling.

The proposed process contributes to significantly improve wellbore placement through the pay zone while drilling. Reduced trajectory positional uncertainties contribute to the construction of sound geological models for rational well target design, positioning and development pattern fine tuning during the drilling campaign. In turn reservoir management including mature fields shall benefit from improved Wellbore Placement as a multidisciplinary task by locating more accurately layer tops and contacts.
Raising Employee Awareness of HSE Risk: Using Hazard Observation Programs in Russia—Lessons Learned
Authors: Jumagaliev Marat , Knode Tom , Samoylova Olga
Published: December 2007

A hazard observation program is a core element of a proactive health and safety risk management approach. Early identification and robust communication of the hazards in the workplace accompanied by a timely follow-up on safety concerns play an essential role in mitigating the occupational risks and improving health, safety, and environmental performance.

The information coming directly from the people immediately exposed to the worksite environment brings unique value to the scope of health and safety risk awareness and risk reduction programs maintained by organizations. Another important benefit of the program is engaging every single person in the company in the process of identifying and eliminating risks they encounter in their daily job. Employees watching out for the hazards ultimately embrace a responsibility for their own safety and for the safety of the peers working next to them. This can be considered a first step toward making a difference in safety on behavioral and attitudinal levels.

While the concepts described above are well known to the oil and gas industry globally and should be easy to grasp, most companies in Russia have not implemented them. This paper describes how a hazard observation program was launched throughout company locations in the region and how it works today. Sharing the history of the initiative in Russia, common challenges and success stories may help to encourage local companies to employ the hazard observation tool for raising employees' awareness of the existing health and safety risks and for mitigating those risks to make a Russian oil field a safer place to work.
Russian Mature Fields Redevelopment
Authors: Cimic Miljenko
Published: December 2007

Redevelopment of mature oil fields is becoming increasingly important in Russia and worldwide. An extensive application of new ideas, coupling reservoir management and production enhancement of mature oil fields, is outlined in this paper. Discrepancies in the pressures, production and injection data can create significant errors in reservoir simulation models. Uncertainty should be acknowledged and accounted for during the history matching and reservoir simulation process. In many cases large amounts of historical data were collected but much is either inaccurate or critical types of data have not been gathered. Lots of Russian fields have great potential using modern techniques but each project has great uncertainty due to data constraints.

A strategic goal for Oil Company is mature fields redevelopment using new technology and approaches, in order to enhance oil production. Brown fields are suffering from serious reservoir management problems and field redevelopment strategies are based on significant improvement of the reservoir management and water flooding, development of new water injection patterns, which means idle producers/injectors recovery and production enhancement work on existing wells. The conclusions and recommendations of the paper include suggestions for ways to solve these problems. An understanding of historical data errors is not enough to guarantee reliable simulation models; reservoir description uncertainties and errors will always be an important driver of the model results.
The Physics of Steam Injection in Fractured Carbonate Reservoirs: Engineering Development Options that Minimize Risk
Authors: Shahin G. T. , Moosa R. , Kharusi B. , Chilek G.
Published: December 2007

Naturally fractured carbonate reservoirs hold well over 100 billion barrels of heavy oil worldwide. Thermally Assisted Gas Oil Gravity Drainage (TAGOGD) is a new and novel thermal EOR technique, which has applicability in selected reservoirs. In conventional isothermal GOGD, vertical fractures cause the gas-oil contact in the fracture system to advance ahead of the gas-oil contact within the matrix blocks, causing the oil in these blocks to become mobile. The addition of heat in the fractures generates additional hydrocarbon gas cap, lowers the viscosity of the oil, and accelerates conventional GOGD, as seen in the 220 cp heavy-oil Qarn Alam field in Oman. Pilot results in the Qarn Alam field support the commerciality of this process, and a first-of-it's-kind steam injection project is being implemented. The economic success of the Qarn Alam project depends on the ability to credibly predict steam requirements and oil production. Two key oil production mechanisms are heat transport through the fractures and into the matrix, and subsequent gas cap generation due to thermal volatilization of the oil. The process mechanisms involved in TAGOGD were validated through laboratory experiments, while the field forecast model results were validated by history matching pilot performance data. A fully integrated workflow of fracture characterization, integrated reservoir physics, and static and dynamic modeling has enabled uncertainties and risks involved in developing the Qarn Alam field to be managed in a scenario based design approach.
Application of Integrated Reservoir Studies and Probabilistic Techniques To Estimate Oil Volumes and Recovery, Tengiz Field, Republic of Kazakhstan
Authors: Dehghani K. , Jenkins S. , Fischer D. J. , Skalinski M.
Published: December 2007

Probabilistic methodologies have yielded new insights into oil volume and recovery for Tengiz Field, Republic of Kazakhstan. Tengiz is one of the deepest super-giant oil fields in the world, and is located on the shore of the Caspian Sea. Knowledge of the uncertainties inherent in oil recovery is a key to proper reservoir management of Tengiz Field.

Both structured Monte-Carlo and Experimental Design techniques have been used to investigate the interaction of key uncertainties for this deep, super-giant oil field. Probabilistic approaches have provided information about the most likely oil volume and production and give insights into the probable ranges of oil volume and production. This paper describes the methodology and technical studies conducted in support of the 2005 reservoir model for Tengiz Field.

A structured Monte-Carlo Technique has been used to construct several thousand static models of Tengiz Field. Construction of Monte-Carlo models is very fast and allows the impact of key uncertainties to be explored. Key reservoir uncertainties include structural elevation, geostatistical parameters (such as variogram length), the Bulk Volume Water (BVW) constants for each stratigrahic interval, the location of the boundary between facies intervals, and the extent of porous facies and altered (dolomitized) zones, etc.

Investigating the uncertainty in the dynamic performance of the model is much more computationally intensive. Experimental Design techniques minimize the number of computationally expensive simulation runs. Dynamic variables investigated include: oil in place, permeability enhancements, vertical to horizontal permeability ratio, well productivity, the water oil contact depth, and production capacity.

At Tengiz, uncertainties in variables which are "random" or vary spatially across the field have much less impact than uncertainties which can have systematic uncertainty. Examples of systematic uncertainty include wire-line to core calibration of porosity and saturation. This study also showed that for a specific development scenario the oil in place, gasoil relative permeability, and ratio of vertical to horizontal permeability, had the most impact on the estimated oil recoveries.
Waterflooding Surveillance and Monitoring: Putting Principles Into Practice
Authors: Terrado M. , Yudono S. , Thakur G.
Published: December 2007

This paper illustrates how practical application of surveillance and monitoring principles are keys to understanding reservoir performance and identifying opportunities that will improve ultimate oil recovery. Implementation of various principles recommended by industry experts is presented using examples from fields currently in production.

Practices on how to process valuable information and analyze data from different perspectives are presented in a methodical way on the following bases: field, block, pattern, and wells. A novel diagnostic plot is presented to assess well performance and identify problem wells for the field.

Results from the application of these practices in a pilot area are shared, indicating that the nominal decline rate improved from 33% to 18% per year without any infill drilling. The change in the decline rate is primarily attributed to effective waterflood management with a methodical approach, employing an integrated multi-functional team.

Although the suggested techniques can be applied to any oil field undergoing a waterflood, they are of great value to mature waterfloods that involve significant production history. In these cases, prioritization is a key aspect to maintain focus on the opportunities that will add most value during the final period of the depletion cycle. Case studies illustrating the best surveillance practices are discussed.
Utilizing Computational Fluid Dynamics (CFD) Analysis as a Design Tool in Frac-Packing Applications To Improve Erosion Life
Authors: Clem N. J. , Coronado M. P. , Mody R. K.
Published: December 2007

Frac packing tool erosion is becoming a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbs. As zone lengths are increased and multi-zone operations are performed jobs requiring 60 bbl/min pump rates with proppant loads reaching 900,000 lbs. may be more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells.

Computational fluid dynamics (CFD) analysis of these systems provides valuable insight to what is physically happening to the tools at these high pump rates and proppant loads. Analyzing various patterns, such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization. CFD analysis is a cost effective alternative to trial-and-error testing, which can cost upwards of $150,000 per test and prolong the development phase.

Two sizes of systems have been analyzed using CFD analysis and modified based on the results of that analysis. Full scale tests were also performed at 40 bbl/min on these two systems to compare the actual results with that of the CFD analysis. The CFD analysis was able to generate accurate profiles of the physical erosion patterns observed after the full scale tests were completed. Although CFD cannot accurately predict magnitudes for erosion rates, it can predict erosion profiles and velocity magnitudes. Research is currently ongoing to accurately predict erosion rate magnitudes.

This paper will detail the development, analysis and qualification testing of a next-generation frac packing system capable of use in ultra-high-rate operations.
Integrated Project Management in South Mexico and Well Construction Optimization on Deep and Depleted Carbonates
Authors: Jenrette M. , Murillo J. , Mandujano H.
Published: December 2007

The Bermudez Complex is located in South Mexico; it constitutes of three main fields: Iride, Samaria and Cunduacan and was discovered in 1972. In terms of oil production it is the most important field in the southern region and is one of the principle blocks in the country. Production exceeded half a million of barrels per day in the past; however since then it has experienced a drastic formation pressure reduction.

Well construction in the area has been characterized by the difficulties experienced in effectively isolating the high pressure zones located just above the carbonates in the reservoir, and by the need to drill the pay zone with hydrostatic equivalents much lower than the ones generated by conventional liquid fluids. The depth of the wells, the structure tectonically disturbed by fractured and faulted blocks, the high temperature and the need for directional drilling control, are variables that challenge the design and drilling of these wells.

Recently, a typical integrated drilling and completion commercial scheme has been implemented in the complex using five large drilling rigs operating simultaneously and managed by an integrated Project Management team allowing flexibility in applying new technologies along with standard products and services.

In spite of the unfavorable and extremely low reservoir pressures, the drilling and completion times have been considerably optimized through the application of several techniques and processes that when properly applied and coordinated allowed the project to reach aggressive goals. The main practices and technologies applied are as follows: drilling with foam densities as low as 2.9 ppg, isolation of different productive zones under hostile environments, use of the latest generation of drilling bits, a process for defining the technical limits and the capturing of best practices/lessons learned, and finally a multidisciplinary task team working closely with geosciences support enabling optimal casing seat on a highly complex geological environment.
Case History—Application of a New PDC Bit Design in Deep Cretaceous and Jurassic Hard Formations in Southern Mexico
Authors: Bejarano C. A. , Muñoz G. , Perez G. , Cortina C. , Palomo R.
Published: December 2007

In the Tecominoacan Field in Southeastern Mexico, discovered in October 1980, approximately 107 wells have been drilled to date. One of the biggest challenges of these wells is drilling the production interval, which is comprised of fractured limestones and dolomites interbedded with cherty stringers.

Historically, of the different bit types and designs tested in the field, the most successful were insert tricone rock bits (IADC 517-537). Even then, multiple trips and low rates of penetration were common while drilling the 8 ½" and 5 7/8" hole sections. Because of natural depletion of the productive formations, penetrating these target intervals requires underbalance drilling techniques that negatively impact bit performance: less bit life due to seal failure, increased trips and decreased bit reliability.

An exhaustive analysis of bit performance in the field, including bit wear comparison, and introduction of new materials led to bit design adjustments based on hard rock drilling concepts. The resulting fixed cutter design, with high density cutters incorporating the latest-generation PDC cutter materials, achieved dramatic performance improvements.

Where typical rock bit performance in Tecominoacan Field wells averaged penetration rates of 4m/hr in 8 ½" and 5 7/8" hole sections, the new PDC bit design doubled that performance, delivering immediate benefits in saved time, fewer trips, longer bit life and less bit wear.

The paper presents case history performance that demonstrates how this hard rock bit technology could be of benefit in other areas with similar lithology and hole conditions.
Material Balance and Boundary-Dominated Flow Models for Hydrate-Capped Gas Reservoirs
Authors: Gerami S. , Pooladi-Darvish M.
Published: December 2007

Gas hydrates are being considered as an alternative energy resource of the future, considering the enormous quantities existing in permafrost and offshore environments. Some of the hydrate reservoirs discovered (e.g., in Alaska and Siberia) are overlying a free-gas layer. These reservoirs are thought to be the easiest and probably the first type of hydrate reservoirs to be produced1.

This paper presents the first-ever developed material balance model for such a reservoir (which we shall call a hydrate-capped gas reservoir). The technique presented herein differs from the traditional approach of applying material balance methods to conventional gas reservoirs because it includes the effects of gas generated from hydrate decomposition and its associated cooling effect. The material balance equation is developed by analytically and simultaneously solving the mass and energy balance equations. The solution yields the average reservoir pressure and the gas generated from hydrate decomposition as a function of cumulative gas produced, for a reservoir that is produced at a constant rate. In the second portion of the paper, we develop a flowing material balance equation by first writing the inflow performance equation, relating the wellbore pressure to the average reservoir pressure and then combining it with the material balance equation. This yields an estimate of initial gas-in-place from production data.

Using a recently developed hydrate reservoir simulator, it is shown that this model is valid over a wide range of reservoir parameters. The success of this model relies on coupling of the energy and mass balance equations, where the energy equation accounts for the endothermic nature of hydrate decomposition.

In its "forward solution" mode, the model developed here is used as an engineering tool for evaluating the role of hydrates in improving the productivity and extending life of hydrate-capped gas reservoirs. In addition, in its "backward solution" or inverse approach mode, the application of this new model is providing an estimate of initial free gas-in-place from production data.
Integration of Borehole Imaging, Openhole Logs, Nuclear-Magnetic-Resonance/Modular Dynamic Tester, and Advanced Production Logging as a Guide for Perforation Intervals Selection in Thin-Bedded Sands and Shales
Authors: Daoud A. M. , Eisa M. , El-Mahdy R. , Emam M. , Hashem A. H. , Elhawary A. S.
Published: December 2007

Specifying the perforation intervals and evaluating the productivity of thin-bedded sands and shales is crucial for well completion cost optimization. This requires the accurate identification of hydrocarbon-bearing sands and their contribution to production. Relying only on borehole-imaging tools to select the productive intervals is not suitable in this lithologic type because of the difficulty of permeability quantification.

In this paper we present a technique to integrate the detection of hydrocarbon-bearing sands with water saturation information and an estimation of permeability. Hydrocarbon-bearing sands are detected by high-resolution resistivity from borehole-imaging tools combined with water saturation from openhole logs (OHL), and permeability from nuclear magnetic resonance (NMR) or a modular dynamic tester tool.

We use the geostatistical concept of indicators to convert the inputs from these tools into binary data (0 and 1) based on the best selected cutoffs for those inputs, where a value of 1 means that location is good to perforate. The results of this integration are compared to the results from the production logging tool that is sensitive to the laminated sand units for evaluating its actual productivity. The best cutoffs to select for those parameters are in good agreement with the production logging tool results. The result is a set of optimized perforation intervals consistent with all the data. In addition to the certainty percent associated with the selection of perforation intervals.

Three gas wells producing from the same formation were used to apply this technique. One of the three wells was used to select the best cutoffs. For the other two wells, we used the same cutoffs to select the best perforation intervals and determine the certainty associated with them. The correct selection of the perforation intervals from the two wells was confirmed with the production testing and production logging results.
Transversly Multi-Fractured Horizontal Wells: A Recipe for Success
Authors: Demarchos A. S. , Porcu M. M. , Economides M. J.
Published: December 2007

While the hydraulic fracturing of vertical wells is perhaps the most widely used method for production/injection enhancement in the petroleum industry, the fracturing of horizontal wells has been used sparsely, mostly in the United States and the North Sea. Usually this involves either longitudinal fractures or treatments with no regard to the well orientation and fracture azimuth.

The systematic transverse fracturing of horizontal wells poses several challenges in design and optimization and in operations and execution. A multi-fracture design and a feasibility study are performed to identify candidates for both a technical and an economic success. We used a fractured vertical well as the basis of our calculations and we have determined the dimensionless PI as the means to evaluate the attractiveness of multiple transverse fractures intersecting a horizontal well.

In previous publications we have presented the Unified Fracture Design and how its adaptation by several companies and researchers led to major new successes. The drainage shape and flow regime in transversely fractured wells differs significantly from vertical wells. The Unified Fracture Design had to be adapted with shape factors to account for the differences. We are showing a series of designs using a range of sizes of fracture volumes, different proppant types and drainage sizes.

For treatment execution, traditional methods of perforating may increase the probability of failure. The types of reservoir which are candidates for these treatments such as multi-layered reservoirs will almost surely affect the fracture initiation, and, as usual, composite materials show higher mechanical resistances compared to homogeneous materials. A new abrasive jet cutting tool has now been designed and built specifically for this type of jobs.

In this paper we will present all the design and operational challenges that will be faced in such fracturing project, and make recommendations for successful treatments
Analytical and Numerical Solution of Nonisothermal Buckley-Leverett Flow Including Tracers
Authors: Sumnu-Dindoruk D. , Dindoruk B.
Published: December 2007

Mass balances for two immiscible fluids and tracer and convective heat balance form a system of three equations (non-isothermal Buckley-Leverett Problem - ref. 1 -with Tracers). Tracer component is considered to investigate the propagation of a tracer in order to track the flood (or to track a miscible inert contaminant introduced during drilling). We have solved the resulting non-isothermal two-phase convective flow equation in porous media analytically, including a tracer component (i.e., cold or hot waterflooding with and without tracer). Method Of Characteristics (MOC) is used as a solution technique after transforming the balance equations in a form that can easily be solved with two Welge tangents (refs. 2-7). Our solution technique is valid for both radial and linear flow models.

In practice, these solutions can be used:To investigate the convective flow behavior around the wells (i.e., sudden fluid losses, convective near-well tracer propagation, analyzing pressure transients).To interpret formation testing tool responses by detecting the location of the thermal front or to estimate the temperature buildup time that is needed for Horner type of analysis (for the identification of the formation temperature).To calculate the location of the cold or hot water front (thermal water) while injecting cold or hot water. This will yield the limit of the maximum temperature disturbance around the well.To test/scale relative thermal effects of various systems against each other.To test the accuracy of simulators and provide benchmark solutions.To interpret relevant laboratory experiments quickly.

Such solutions helped us to understand the depth of influence of the temperature variations and its influence on the transport properties, in both radial and linear systems. Solutions analytically proved that the thermal front propagates much slower than the flood front. This explains why isothermal black oil simulators still work although the injected water temperature is not always equal to the reservoir temperature.

Furthermore, we have checked/verified our results against a commercial thermal simulator (ref. 8) and investigated the impact of numerical diffusion on the thermal front as well as conductivity. This part of the work revealed that the temperature front is more prone to numerical diffusion.
Generation of Curves of Effective Gas Separation at the ESP Intake on the Basis of Processed Real Measurements Collected in the Priobskoye Oil Field
Authors: Gadbrashitov I. F. , Sudeyev I. V.
Published: December 2007

Well performance monitoring is extremely useful to effectively control hydrocarbon production and make timely decisions when it comes to run various well interventions. The more ample and correct are the data at our disposal, the more efficient will be the management. Traditionally little attention is given to the gas liberated at oil degassing and no measurements are taken; although this kind of data would allow computing a number of rather critical figures, such as gas content in the mixture, bottomhole pressure, etc.

For the moment maximum 20% of all the wells in the Priobskoye field are outfitted with the PHD sensors, and the BHP as well as the pressure at the ESP intake for the most of the wells are computed. This kind of computation requires an ESP separation efficiency function. However, all the available efficiency-function computation equations are based on tests run on recombined liquid/gas mixtures at lab setups, that is, under ideal conditions.

In this paper we put focus on the efforts to evaluate the free gas separation at the ESP intake; estimate the bottomhole pressure based on production data; and assess the gas separation impact on both the pumping unit performance (variation of Q-H characteristics) and the in the tubing and annulus flow parameters.

Measurements of the dynamic level and wellhead annulus pressure that vary with time and allow computation of the fraction of the gas separated were used as input data. As well as the data collected with the PHD sensors, or pressure gauges below the ESP.
Semiautomatic Multiple Resolution Design for History Matching
Authors: Li B. , Friedmann F.
Published: December 2007

History matching is an inverse problem, in which an engineer calibrates key geological/fluid flow parameters via fitting simulator's output to the real reservoir production history. It has no unique solution, because of insufficient constraints. History match solutions are obtained by searching for minima of an objective function below a pre-selected threshold value. Experimental design and response surface methodologies provide an efficient approach to build objective functions (OF) for history matching. The search for minima can then be easily performed on the reconstructed OF as long as its accuracy is acceptable.

In this paper, we first introduce a novel experimental design methodology for semi-automatically selecting the sampling points, which are used to improve the accuracy of reconstructed non-linear OF. This method is based on derivatives of reconstructed response surfaces.

We propose an iterative procedure for history matching, applying this new design methodology. To obtain the global optima, the objective functions are initially constructed on the global parameter space. The objective function is iteratively improved until adequate accuracy is achieved. We locate sub-spaces in the vicinity of the optima regions using a clustering technique to improve the accuracy of the reconstructed OF in these sub-spaces.

We test this novel methodology and history matching procedure with two waterflooded reservoir models. One model is the Imperial College fault model1. It contains a large bank of simulation runs. The other is a modified version of SPE92 benchmark problem. We demonstrate the efficiency of this newly developed history matching technique.
CO2 Sequestration in Depleted Gas/Condensate Reservoirs
Authors: Shtepani E.
Published: December 2007

Depleted gas condensate reservoirs are becoming important targets for CO2 sequestration.

Since depleted below the dew point, retrograde condensate has been deposited in the pore system. CO2 injection in the depleted gas condensate reservoirs may allow enhanced gas recovery by liquid re-vaporization and reservoir re-pressurization or pressure maintenance.

The higher density of CO2 relative to gas condensate means that CO2 will tend to migrate downward. The larger viscosity of CO2 ensures that displacement of hydrocarbon gas phase by CO2 will be a displacement with a favorable mobility ratio. Furthermore, pressure diffusivity is typically several orders of magnitude larger than molecular diffusivity, making mixing by re-pressurization occur much faster than by molecular diffusion.

This paper discusses an approach that relates primarily to the laboratory and modeling studies that precede compositional simulations and field pilot testing of CO2 sequestration in depleted gas condensate reservoirs.

The phase behavior of CO2/gas condensate system as a critical factor in determining the effectiveness of a reservoir to store CO2 are reviewed along with its importance in building an accurate EOS model.

In addition to PVT experiments, a special core flood test design to determine the micro-scale conformance of the CO2 displacement, to identify CO2 breakthrough characteristics at density and compositional level during liquid re-vaporization and re-pressurization process and to evaluate the recovery performance is discussed in detail.

The results from experimental data can be used as a base for sensitivity case studies using a commercial compositional simulator to evaluate the feasibility of CO2 sequestration in depleted gas/ condensate reservoirs with enhanced gas recovery component.
A New Integrated Approach to Obtain Reliable Permeability Profiles From Logs in a Carbonate Reservoir
Authors: Balossino P. , Pampuri F. , Bruni C. , Ebzhasarova K.
Published: December 2007

Permeability is one of the key petrophysical parameters in reservoir evaluation. Information about permeability is commonly derived from cores and test data, that generally cover only part of the reservoir section, but can also be derived from logs, and then extrapolated to uncored intervals and wells. Two logs provide such information: acoustic and nuclear magnetic resonance. In the Karachaganak Field, an approach based on the acoustic tool was preferred because of the textural characteristics of the vuggy carbonate reservoir.

The approach relies also on the use of image logs to obtain a detailed description of reservoir rocks texture and discriminate between rocks with primary interparticle porosity or very small vugs and lithotypes with multi modal distribution of pores, enlarged and touching vugs.

More than 900 meters of core have been used to validate the permeability log derived from the analysis of Stoneley waves in 25 wells from this field. A correlation between the validated log derived permeability and the textural facies from image logs, has allowed the relationship between permeability variations and the geological framework to be established.

The results have been compared with dynamic data from production logging through the definition of flow units from Stoneley wave-derived permeability and porosity log data and the use of a Stratigraphic Modified Lorenz Plot to identify possible fluid entry points.

Three main permeability trends have been identified: for undolomitised or patchily dolomitised biohermal deposits.for pervasively dolomitised lithologies characterised by lower mean permeability values.for facies characterised by well developed vuggy porosity with enhanced dissolution phenomena (touching vugs, microfracturing etc.)

Besides the presence of very high K values clearly unmatchable by log derived matrix permeability has been highlighted by some well test result. This great difference suggests the presence of fracturing improving matrix characteristics in the volume investigated by the test and the well performances.

The comparison of log derived permeability and well test results has given a new perspective in the interpretation of well test results with respect to the geological framework and a well defined sequence stratigraphic model. The extension of this methodology to new wells could improve the knowledge of the petrophysical characteristics of the reservoir and allow better prediction of reservoir productivity.
A Novel Approach for Drilling and Gravel Packing Horizontal Wells in the Presence of Reactive Shales Using a Solids-Free Synthetic Fluid
Authors: Aragao A. F. L. , Quintero L. , Martins A. L. , Calderon A. , Sa A. , McKellar A. , Gabrysch A. D.
Published: December 2007

Drilling of build-up and horizontal sections in a single step is an attractive design approach aimed at cost reduction and increased performance efficiency in offshore field development, including the reentry of old wells in mature fields – infill drilling.

Most of the large production wells in sandstone reservoirs require sand control due to the poorly consolidated formations. Open-hole gravel pack (OHGP) is still the most popular solution for sand control in offshore deepwater reservoirs. The petroleum industry has developed a number of fluid systems for successful OHGP, including using water-based drill-in fluid (DIF) and gravel carrier fluid, or a synthetic DIF and water-based gravel carrier fluid.

In spite of the industry's effort to develop high performance water-based fluids, the use of synthetic fluids guarantees superior wellbore stability, lubricity, inhibition and drilling performance. Substituting synthetic DIF for water-based gravel carrier fluids is a complex operation, due to the potential for fluid interaction, formation damage and problems of offshore logistics. Another challenge is to provide a reliable sand control technique in the horizontal section with operational safety and minimum formation damage.

This article proposes a new approach that utilizes a synthetic fluid for all steps of the well construction and completion. Using a solids-free invert emulsion synthetic fluid as the carrier medium to pack the gravel (IEGPF) in a conventional alpha-beta wave deposition technique eliminates the need for introduction of a water-based fluid.

The goal was to optimize the synthetic fluid to provide Newtonian behavior (including low-shear rate viscosity), minimize viscosity for a given density, compatibility with the drilling fluid, minimum formation damage, wellbore stability, and gravel wettability.

Experiments were conducted using a large-scale acrylic flow loop to evaluate the performance of the synthetic fluid as a carrier medium in horizontal gravel packing operations. Alpha wave deposition heights and packing qualities were measured for different proppant materials and densities. The resultant fluid formulation has densities ranging from 9.0 to 10.5 ppg, and guarantees proper alpha-beta wave gravel deposition and minimal formation damage.
Neural-Computer Modelling for Reservoir Properties Prediction from Stochastic Seismic Inversion Results
Authors: Gritsenko A. M.
Published: December 2007

This report is dedicated to description of complex reservoir properties prediction method using neural-computing for stochastic seismic inversion results processing. Some case studies are provided.

It is very important for successful reservoir properties prediction using seismic and well log data to take all a priori geological and geophysical data into account correctly. Stochastic seismic inversion results (cubes of pressure and shear velocities, density, impedance) are defined all over the area of survey, fully correspond with seismic wavefield and with a priori geological and geophysical information too. Refined geological model possesses higher vertical resolution (due to reduction of reflections interference) and provide dimensional physical values unlike seismic amplitude. Application of neural-computer technology with integrated prediction stability check mechanism (Jack-Knife), provide reservoir properties prediction quickly and guarantee good quality.