bluuebunny/crossref_metadata_2025 huggingface dataset:
Stochastic History Matching and Data Integration for Complex Reservoirs Using a Wavelet-Based Algorithm
Authors: Sahni I. , Horne R. N.
Published: December 2007

This work develops a generalized wavelet-based methodology for stochastic data integration in complex reservoirs models. This is an extension of our earlier work for simpler reservoir descriptions (Sahni 2003; Sahni and Horne 2005, 2006). A single history-matched reservoir permeability model is combined with a stochastic geological description to obtain multiple equiprobable reservoir descriptions using wavelet transforms of the parameter distribution (permeability). In this paper the algorithm has been extended and generalized to be usable with commercial reservoir simulation software and to enable handling of complex three-dimensional models and production scenarios. We also conducted a study of sensitivity coefficient distributions, thresholding and averaging techniques, and a comparison of different Haar wavelet implementations.

Wavelet coefficients of reservoir parameter distributions are decoupled into sets of history-matching and geologic coefficients and modified independently. Inverse transformation of these coefficients yields multiple reservoir model results, all of them matched to history. A significant reduction in time is obtained for stochastic modeling of reservoirs by use of this decoupling of production data and other parameters, since only a single history match is required.

Thus the proposed algorithm addresses the issue of stochastic modeling of complex reservoirs by integrating all available sources of information. From a single history-matched model we obtain a set of distinct equiprobable reservoir models that can then be used to evaluate uncertainty and make future production predictions and reservoir management decisions.
CO2 Transport Mechanisms in CO2/Brine Coreflooding
Authors: Grigg R. B. , Svec R. K.
Published: December 2007

Concerns for the possible consequences of increased greenhouse gas emissions will undoubtedly increase carbon dioxide (CO2) injection into oil reservoirs for enhanced oil recovery (EOR) and probably into other geological formations for sequestration.1 The development of CO2 plumes and subsequent dissolution into formation brine are essential mechanisms in most sequestration scenarios and could aid in understanding long-term injectivity reduction in EOR WAG (water alternating with gas injection) projects. This paper describes laboratory tests on sandstone and carbonate core samples. Two types of displacement tests were performed; gas injection to a residual brine saturation with respect to gas, followed by brine injection to a residual gas with respect to brine. The level of CO2 saturation in the injected brine at reservoir pressure and temperature was varied from zero to over 90% saturation. Sandstone and limestone rock types were tested. This variation in CO2 saturation in the injected brine was to determine the effect on the CO2 saturation or plume size in the core. This information can be used in CO2-EOR-WAG projects and carbon sequestration into geological formations.

By injecting CO2 into brine-saturated Frio sandstone the brine saturation was reduced to 68–71% in each of five tests. In each test, over 90% of the reduction occurred with less than 0.33PV of CO2 injected, with very little additional brine production after 0.5PV of CO2 injected. During brine injection, CO2 production was equivalent to the rate expected from brine saturated with CO2 at the reservoir conditions. This indicates that for Frio core at high irreducible brine saturation at the tested flow rate (~6 ft/day), the CO2 plume was reduced through dissolution, not displacement. With increasing CO2 saturation in the injected brine, the brine volume required to remove (dissolve) the CO2-plume increased proportionally. Results will be used to aid in predicting injectivity in CO2-EOR-WAG operations and CO2 plume migration and dissolution in EOR and sequestration. The principle mechanisms for CO2 saturation reduction are identified.
Wellbore Cooling as a Means To Permanently Increase Fracture Gradient
Authors: Gil I. , Roegiers J. -C. , Moos D.
Published: December 2007

In recent years, several techniques have been proposed to increase the fracture gradient by inducing changes in the near wellbore region (Alberty and McLean, 2004; Sweatman, et al., 2004;Benaissa et al., 2005). This process, often called "wellbore strengthening", has most recently been implemented by adding specially designed proppant material to the mud before raising its pressure above the fracture gradient. The goal was to induce short tensile fractures in the vicinity of the wellbore wall which are prevented from propagating; thus, creating a "stress cage". However, this method has often proven ineffective in low permeability formations where mainly uncontrolled fracture propagation occurs.

The purpose of this paper is to propose and evaluate the use of wellbore cooling, in combination with more classical stengthening processes, to permanently increase the fracture gradient without the risk of circulation losses inherent in the "stress cage" method, as it is currently applied. This approach involves lowering the temperature of the drilling mud; thus, reducing the hoop stress at the borehole wall and then ‘setting’ the stress cage in the standard manner. Tensile cracks can then be induced at significant lower mud weights. Given the typical thermal conductivity properties of rocks,the tensile stresses induced by cooling (and consequently, the created fractures) will tend to be confined to the near wellbore region.

This work presents an evaluation of the effect cooling has on the stress profile of a "solid" material and compares it with a fully coupled thermoporoelastic solution. The results of such analyses may then be used to design a field application to test this novel idea.
Continuous Fracture Modeling of a Carbonate Reservoir in West Siberia
Authors: Pinous O. , Zellou Abdel M. , Robinson Gary , Royer Ted , Svikhnushin N. , Borisenok D. , Blank A.
Published: December 2007

The field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of the matrix are generally negligible, and the production potential of wells is mostly associated with natural fractures and vugs.

The presented study was our first project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs processing, 2) Spectral imaging and high-resolution inversion of the seismic data, 3) structural analysis of the field, 4) construction of the reservoir properties model, 5) construction of the fracture distribution model using the Continuous Fracture Modeling approach (CFM). A comprehensive description is available on a previous publication1.

The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well, showed a good level of correspondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually, the well showed a good production results and currently is one of the best producers in the field.

As such, we recommend application of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation.
Underbalanced Drilling In The Reservoir, An Integrated Technology Approach
Authors: Ramalho John
Published: December 2007

Shell is a major player in the Global deployment of Managed Pressure Drilling (MPD) technology to reduce drilling problems, minimize formation damage and improve reservoir management techniques.

The impetus is a recognition that most of the world's mature hydrocarbon reservoirs are in the lower end of the depletion cycle and an increasing number of horizontal wells are left with un-cemented completions. In addition, to access new untapped reserves, requires venturing into deeper water depths and the exploitation of deeper tight gas reservoirs, each with its own challenges.

This paper describes the process involving rigorous pre-screening, planning, execution and feedback of learning developed that enables fast implementation of underbalanced drilling (UBD) and integrated technologies into "Brown Field" areas and new business opportunities in "Green Field" development.

This begs the question; what is Managed Pressure Drilling technology and what is the relationship with underbalanced drilling?

The International Association of Drilling Contractors (IADC) defines Managed Pressure Drilling as "an adaptive drilling process used to precisely control the annular pressure profile throughout the well bore. The objectives are to establish the down-hole pressure environment limits and to manage the annular hydraulic pressure profile accordingly".

In a sense managed pressure drilling, covers all drilling, since management of pressure is the goal of all drilling activities. However, there is general industry agreement that Managed Pressure Drilling is an umbrella term that refers to drilling activities conducted in a closed loop system. Conventional overbalanced drilling sits at one end of the Managed Pressure Drilling spectrum and underbalanced drilling at the other end.

In conventional drilling, bottom hole pressure is managed by controlling the density of the drilling fluid to maintain well bore pressure profile above the pore-pressure throughout the well bore. Underbalanced drilling on the other hand, the well bore pressure profile is intentionally kept below the pore-pressure of all the exposed formations in the well bore. In between these two extremes are various techniques used to control the annular pressure profile and overcome constraints imposed as a result of the equivalent circulating density of the mud system. Seen from Shell's perspective, Managed Pressure Drilling is a basket of drilling techniques that can be adapted to solve drilling related problems, reduce formation damage and or dynamically characterize production reservoirs (while drilling) to enable improved reservoir management. It is also worthy to note that not all Managed Pressure Drilling techniques require a closed loop system.
Next Generation Reservoir Simulation Using Russian Linear Solvers
Authors: Beckner B. L. , Usadi A. K , Ray M. B. , Diyankov O. V.
Published: December 2007

During the late 1990's, Exxon and Mobil had each independently developed next-generation reservoir simulation systems. Both next-generation systems embodied a substantial number of step-out simulation technologies, which were extremely complementary. ExxonMobil moved aggressively to combine the best of both companies' technologies into one industry-leading simulation system called EMpower™. This new simulation system is currently being used to actively manage ExxonMobil's global resource base. Key features of this industry-leading simulator are described in this paper.

The new simulator employs unstructured grids to more accurately model complex geologic features, near-wellbore flow, and aquifer support. The computations are performed within the unstructured grid fabric. Interactive simulation ties together the geologic and reservoir simulation models with production data yielding high-confidence forecasts of future performance.

The linear systems that are created by an unstructured grid cannot be efficiently solved by conventional solution methods normally applied to simulators using rectilinear gridding. As a result, ExxonMobil looked to collaborate on research and development activities in the area of linear solvers for unstructured grids area and found capable research and development peers in Russia. The technical capabilities of the Russian scientific community were a natural fit to help develop a new library of linear solution methods geared towards the matrices created by the EMpower unstructured simulator. This collaborative effort yielded an unstructured linear solution library called SparSol and is the result of over 20 work years of effort at four Russian research organizations and contains numerous methods for efficiently solving the unstructured matrices produced by the EMpower unstructured reservoir simulator.
Reservoir Engineering Production Optimization System for Effective Field Management and Perfomance
Authors: Gladkov A. V. , Zakirova G. F.
Published: December 2007

Effective management of field development is based on daily routine engineering calculations and monitoring key performance indicators of production. At the same time it is recognized through the industry that there exists a gap between reservoir engineering and decision making process for real time reservoir management.

Whatever software one uses it will not be very useful if an engineer cannot get right input data in the proper format in time and manager is constrained in getting information for quick decision making.

Reservoir Engineering Production Optimization System is engineering information portal, which provides wide web based environment for production engineers and management of oil companies.

The system gives field data access such as well logs, core data, logs interpretation and perforation data, interactive cross sections, geological maps, PVT fluids properties, daily and monthly production, well stock information and well events.

Revolution approach is that portal provides an ability to perform standard engineering calculation from any place in corporate network. PVT correlation, well bottom-hole pressure and productivity calculations are few of them. It allows using only web browser to build log curves and well's IPR curves, to estimate artificial lift efficiency. It gives the opportunity to download data in standard software format and reduce data gathering time.

Portal presents basic collaboration environment features. News, forums, links, documents storage and engineering utilities build distributed collaborative environment and provide effective tools for knowledge management and dissemination company wide.

We believe that portal can add more value to the assets being properly tailored to specific needs of organization. This system is developed to enable robust and timely decision making for oil companies and is successfully implemented in one of them in Russia.
Seismic and Well Log Reprocessing, Re-interpretation and Geostatistical Inversion Yields More Detailed View of Yuzhno Khilchuyu Field
Authors: Fossum Bret , Snow John , Guilloux Yoann , Jason Fugro , Khromova Inga , Chernitskiy Andrey , Glebov Aleksey
Published: December 2007

LUKoil and ConocoPhillips formed the joint venture company NaryanMarNefteGaz (NMNG) to develop jointly owned licenses in the Timan-Pechora Basin. The Yuzhno Khilchuyu license lies in this province and, is expected to be one of the largest and most prolific fields in the region. Development of the Yuzhno Khilchuyu Field requires a huge initial investment in infrastructure, drilling and transportation. Successfully achieving acceptable reserves and production levels from the field will be critical to offset these investments. To meet this challenge a more detailed understanding of the reservoir is needed to optimize well placement.

In 2004, a large multi-disciplinary subsurface project team was formed with members from LUKoil, ConocoPhillips and Fugro-Jason to develop updated high-resolution geologic and reservoir simulation models. The seismic and well log data were completely reprocessed, resulting in a significant improvement in the overall data quality. All log, core, and production test data were incorporated into a new, fully integrated, interpretation. A sophisticated Markov Chain Monte Carlo (MCMC) geostatistical inversion methodology was applied, and the resulting high-resolution geologic model yields a dramatic increase in reservoir detail. The new model enabled the team to define the aerial extent of different reservoirs and the distribution of internal barriers. It also provided insight into porosity and permeability distribution within each reservoir, enabling better decisions on the location of production and water injection wells. Development drilling is in progress.
Well Work Challenges in a Matured Offshore Operations
Authors: Ismail Abdul Malek , Ahmad Azmeer , Lane Tom
Published: December 2007

This paper will address and discuss the planning and operational challenges encountered in non-routine wellwork operations / well interventions in ExxonMobil Exploration and Production Malaysia Inc. (EMEPMI) oil and gas fields off the east coast of Peninsular Malaysia.

The introduction will provide a brief overview of EMEPMI wells, typical conventional workover rig (CWR) and non-rig wellwork operations such as coiled tubing operations, well servicing and wireline/slickline work. Subsequently, case examples will describe the planning and execution of non-routine non-rig wellwork operations, namely:–Coiled tubing milling of tubing retrievable surface controlled subsurface safety valve (TR-SCSSV) dislodged flapper,–High angle coiled tubing operations; static bottom hole pressure (SBHP) survey, setting tubing plug and sleeve shifting at well angle in excess of 75°,–High angle coiled tubing operations; setting through tubing inflatable packers at 88° well angle,–High angle well interventions with slickline; slickline fishing, and–Hot tap milling of stuck closed production casing x production tubing annular (B Section) wellhead valve.

Finally, the conclusion of this paper will share general lessons learned from the case examples in terms of applying best practices, planning the work and executing the work.
Formation Pressure Application for Correlating Miocene Turbidite Reservoirs in the Deepwater Gulf of Mexico
Authors: Russell C. , Luise N. , Kuecher G. , Lee J.
Published: December 2007

Thick allochthonous salt masses that pierced the seafloor in the formation of salt-cored folds flowed laterally downdip to form canopies above turbidite exploration targets. This acoustic configuration has created ray path and contrast difficulties for seismologists attempting to carry reservoir reflections beneath the salt and updip to their terminations against it. Initial attempts to correlate these turbidite channel and sheet reservoirs include standard log goodness-of-fit methods, paleontology, surface seismic, and expected hydrocarbon occurrences such as gas-updip-to-oil or oil-updip-to-water. Unfortunately, these methods seldom provide a definitive correlation. Formation pressure data, however, does prove effective in correlating and defining connectivity in these deepwater sediments, especially when exacting pressure gradients and detailed hydrocarbon characterizations have been performed.
HP/HT Drilling Fluids Challenges
Authors: Bland Ron , Mullen Greg , Gonzalez Yohnny , Harvey Floyd , Pless Marvin
Published: December 2007

Accurate knowledge of drilling fluid behavior under actual conditions is required to maximize operational efficiency and to minimize cost and drilling fluid related risks on extreme high-pressure / high-temperature (HP/HT) wells.

This paper identifies and discusses the major HP/HT drilling fluid challenges, recent innovations in fluid viscosity measurements under HP/HT conditions, drilling fluid designs stable to extreme HP/HT conditions, and other considerations in HP/HT drilling.
Experience of Using Services By Local and Foreign Companies in Drilling Wells on South-Priobskoe Field
Authors: Fecenec R. M.
Published: December 2007

The South-Priobskoye field simulation model was built in 2005 based on the seismic and logging data obtained in the wells of the pilot area. The field development program stipulated 200 wells to be placed on production on the annual basis.

Optimization of drilling process became a key issue to expedite field development and to save costs.

The JSC "SibNeft" hold several meetings with the leading international companies with the purpose to identify the best drilling technologies.

The discussions helped verifying the main approach to settle this issue as follows: drill 200 wells per year as minimum;reduce costs, as it will be the key factor to evaluate the efficiency;reduce drilling time, as it will be the key factor to evaluate the process efficiency;the proposed drilling and completion technologies have been substantiated.

All prospective options to improve the process were reviewed and identified. The proposals covered drilling technologies and other aspects, including drilling equipment upgrade, personnel training and project management issues.

The effect of these improvements was evaluated for all three drilling intervals (324 mm, 245mm and 178 mm). The evaluation method allowed identifying the quantities and prioritizing the improvement options. It also helped to calculate the reduction of time and costs per well. In order to implement the project, we need to properly prepare for it and to build a so-called "learning curve", which will identify time needed to collect the knowledge and the information, which in its turn will ensure the success of the project.

The best quality and profitability in the drilling process can be reached through the proper analysis, learning process and evaluation of the lessons learned, when drilling each individual well.

The key to success is a collective approach, when all the project parties share their interest in the "commercial drilling" project, where almost all aspects are optimized and oriented to the final product with minimum costs and time.
Surface BOP—Recent Experience and Future Opportunities
Authors: Kozicz John
Published: December 2007

Recent application of Surface BOP from floating drilling rigs to drill offshore wells began in early 1996 in the relatively benign environments of Southeast Asia.

The techniques and equipment required to use surface blowout preventers from floating rigs have evolved progressively from the initial application in relatively shallow water benign environments using moored semisubmersible rigs to recent application in very deepwater moderate environments using dynamically positioned drilling rigs (Fig 1).

While much of the industry focus has been on developing floating surface bop deepwater applications, a significant number of wells have been drilled effectively in shallow water depths using Surface BOP drilling units. The appeal for utilizing floating drilling rig-based surface bop technology in these areas is that the technique can address a number of site-specific issues facing bottom-supported rigs. These include:

Bottom-supported rig site assessment issues related to soil conditions. Risk mitigation associated with shallow geo-hazards. Improved operational efficiency compared with conventional subsea BOP or bottom-supported rig alternatives.

Additionally availability of an economic alternative to bottom-supported units effectively expands the available rig fleet thereby mitigating possible rig availability project constraints.

In addition to providing viable alternatives to bottom-supported drilling units in certain shallow water circumstances, floating drilling rig-based surface BOP is more readily adapted to other emerging drilling methods than a conventional subsea BOP configuration.

This paper will:

Review current practice with respect to surface BOP application from floating drilling units. Review alternative applications of surface BOP from floating drilling units Introduce surface BOP from floating drilling units as an enabling technology for deploying emerging drilling methodologies and equipment.
Production Performance Monitoring Workflow
Authors: Stundner M. , Nunez G.
Published: December 2007

The availability of accurate production volumes, at the well level and throughout the production network, is fundamental to the workflows that target the optimization of the economic potential of the reservoir. Without an accurate understanding of production volumes, the company's field development and operational decisions may not support the maximum economic value of the reservoir and can undermine the accuracy of the reserves estimates.

With current Digital Oilfield technology it is possible to measure production volumes at the well level and at intermediate outlets of the production facilities. However, for many fields this isn't a cost effective solution. Building non-parametric (Artificial Intelligence) production rate models based on pressure and temperature measurements has proven to be a valid and cost effective solution.

Several processes are necessary to measure and validate oil production at the well level as follows: Virtual Rate Measurement (VRM): ensuring accuracy of the volumes at the well level.Back Allocation: focussing on accuracy of the volumes at outlets of the facilities. To minimize the error in the volumetric measurements at both ends of the production network, both processes should be reconciled.The reconciliation procedure allows the comparison of the data coming from two different sources. By using this procedure, engineers can detect discrepancies that affect future decisions.

The sum of all these processes working together in a workflow is defined as "Production Performance Monitoring" (PPM).

The objective of this paper is to provide recommendations on how the PPM process should be properly implemented as an automated workflow to improve well productivity as well as to standardize process and data management. To fulfill this objective, the paper will address the following topics: brief introduction of current work practice, processes and workflows descriptions, technology available, real time environment, automated workflow application recommendation and potential benefits.
Multiazimuth Seismic to Well Tie for Fracture Characterization
Authors: Nawab Ramin , Maultzsch Sonja , Yuh Sung , Mouly Benoit
Published: December 2007

One of the ways to optimize the production of tight sand reservoirs is to take advantage of the geometry and density of the existing natural fractures in order to optimally design and locate the production wells. The detailed mapping of the reservoir fracture network is therefore essential.

To achieve such a detailed fracture mapping, a wide azimuth 3D surface seismic acquisition has been acquired and is being processed for azimuthal anisotropy estimation. The azimuthal variations of P-wave AVO and velocity are analyzed in terms of TIH anisotropy. In order to interpret the resulting anomaly maps in terms of fracture orientation and density, it is necessary to tie the measurements of anisotropy derived from the 3D surface seismic analysis to existing well data, such as well bore electric imaging and dipolar sonic logging. The multi-azimuth VSP technique is used to link these measurements with the surface seismic data.

Initial logging measurements carried out over the field show a very clear correlation between open fracture azimuths (determined by borehole electric imaging), the direction of fast shear azimuths (determined by dipolar sonic analysis) and the direction of tectonic maximum stress. Furthermore, the depth intervals with significant anisotropy correspond to the producing reservoir units.

Multi-azimuth VSP surveys are used to tie the interpretations of azimuthal anisotropy, carried out at the seismic scale, to the anisotropy and fracture measurements, which have been carried out inside the wells. Such well-seismic surveys should help to guide the surface seismic anisotropy processing by identifying the most suitable anisotropy attributes. It should also help to tie the 3D fracture interpretations to the well anisotropy and fracture observations.

Optimized multi-azimuth VSP surveys have been designed to link the ongoing surface seismic azimuthal anisotropy analysis to available well measurements.

The survey design is based on both 3D anisotropic modeling and synthetic multi-azimuth VSP data analysis.

This paper presents preliminary results on the multi-azimuth seismic anisotropy to well tie.
Horizontal Drilling Application to Recover Incremental Oil in Low-Permeability Carbonate Reservoirs, Partitioned Neutral Zone
Authors: Tran Thanh , Barge David , Ingham Stan
Published: December 2007

The Ratawi Oolite carbonate reservoir in the Partitioned Neutral Zone (PNZ) is located between Kuwait and Saudi Arabia and has been a prolific oil producer in the area. Several billion barrels of oil from this reservoir has been produced within the PNZ. As the fields mature, the easy produced oil in the high permeability intervals is diminished by increasing water cut. Considerable by-passed oil remains in the tighter and lower quality intervals. These oil reserves cannot be produced efficiently and economically by vertical wells through primary or secondary methods. Without different techniques of drilling and completion, most of the oil in the low permeability intervals will be left unrecovered.

A combination of horizontal drilling with geosteering tools and technology for precise lateral placement in the low permeability reservoirs in addition to a low fluid loss drilling fluid system have resulted in significant incremental oil recovery that would not be produced by existing or additional vertical wells. The success has led to new opportunity for horizontal drilling and horizontal sidetracking targeting low permeability reservoirs in mature fields.
Evaluating Expandable Tubular Zonal And Swelling Elastomer Isolation Using Wireline Ultrasonic Measurements
Authors: Herold B. H. , Edwards J. E. , Kuijk R. V. , Froelich B. , Marketz F. , Welling R. W. F. , Leuranguer C.
Published: December 2007

New completion techniques using expandable casing with swelling elastomers to seal the annulus, or just swelling elastomers used as packers are becoming available. Diagnostic services are required for these new completions such as evaluation of the annular seal, analogous to cement evaluation. Both conventional and new generation Wireline ultrasonic measurements have been used to characterize and possibly evaluate zonal isolation using swellable elastomers. So far, the following 360 degs circumferential measurements were studied: Ultrasonic radii, acoustic impedance (AI), as well as attenuation and third interface Echo (TIE) reflections from flexural wave data. Radii measurements show a "springback" effect, indicating that expansion against the formation has been achieved. Flexural attenuation has a much better dynamic range over the elastomer sections compared to the acoustic impedance measurements. Both measurements do not consistently distinguish rubber-backed casing with ordinary casing in our examples.

The TIE from the latest generation imaging tool tracking the external rubber interface, may provide the measurement the industry needs. First results look promising and further experiments to characterize the tool response are ongoing. The casing geometry of expanded liners was also studied.
Thermal Design of Wells Producing Highly Viscous Oils in Offshore Fields in the Gulf of Mexico
Authors: Ascencio-Cendejas F. , Reyes-Venegas O. , Nass M. A.
Published: December 2007

This paper shows the results of conceptual studies for the design of thermally bundled wells to optimize the heavy oil production of the offshore fields in the Gulf of Mexico.

During the last recent years, PEMEX has found more offshore reservoirs in the Campeche bay, which contain heavy oils (6-12 °API). Finding more oil is good news at the times that the production from the super giant oil reservoir of Cantarell reached its maximum production level and starts winding down. The economic implications and technical challenges for the exploitation of the recently found heavy oil resources are highly demanding because of the high viscosities of these fluids (40,000 cp at 15 °C) and then the plethora of flow assurance problems that will be generated while producing, transporting, and processing these fluids. Thermal bundled wells will allow an efficient exploitation of these fields.

Heat transfer management achieved through novel and clever thermal design, operation and maintenance of the wells, pipelines and process equipment, maintains the viscosity of the oil at acceptable levels. As to keep an efficient deliverability of the fluid to the surface facilities at the same time that reduces the flow assurance problems, while improves the economics of the exploitation of these fields.
Advanced Technology Improves Drilling Economics/Sets New Benchmark, Southeast Mexico
Authors: Urbieta A. , Martinez M. , Escareño P. , Arias A. , Portillo R. , Castellanos E. , Buske R. , Overstreet J. , Dick J.
Published: December 2007

The majority of the fields in southeast Mexico require 1,000m to 3,400m of 17-1/2 hole to set 13-3/8 casing at the top of Encanto/Deposito formation. Lithology is typically weak sandstone with shale stringers (UCS 2,000-6,000 psi). Operators have attempted to use PDC to drill the hole section in one run with limited success. Operators required an updated steel-tooth rollercone to cut costs by reducing trips/bits to complete the section. Examination of steel-tooth dulls indicated erosive and abrasive wear due to the high sand content was the major factor limiting performance improvement.

To cut drilling time/costs, the service company implemented a new steel-tooth bit with a new generation metal bearing seal and improved cutting structure that has significantly increased total cumulative footage and ROP drilling the 17-1/2" hole section. The metal bearing seal has significantly increased bit life relative to offsetting performance. To further capitalize on increased bearing reliability, the cutting structure has been strengthened by high-performance hardfacing further enhancing tooth/spearpoint durability. New design has added gauge holding ability and reduced cuttings inflow to the seal area further improving bearing life. By comparison, standard steel-tooth bits were often pulled with half to none of the tooth height remaining. This added durability dramatically reduces dulling of the cutting structure allowing the operator to maintain maximum ROP throughout the run while almost doubling total meterage.

The authors will present case studies that document the new bit design has increased meterage by at least 46%, ROP by 12%. Total bit runs have decreased from six to four and the total cone revolutions have increased by 60% compared to average values of best offset runs in several fields. This has saved the operator an average of $140,000USD per 17-1/2" hole section per well.
Simulating Transient Behavior of Cuttings Transport Over Whole Trajectory of Extended-Reach Well
Authors: Naganawa Shigemi , Nomura Tsuyoshi
Published: December 2007

Based on our previously developed prototype simulator, a transient cuttings transport simulator using the two-layer model was developed with some modifications and improvements for more practical use. To evaluate functionality and potential of the simulator, a post analysis on hole cleaning were carried out for an actual extend reach well (ERW) drilled in Japan. Simulation results showed that the modified model successfully demonstrated transient distributions of cuttings bed height and annular pressure over the whole trajectory of the well. From the comparison with a conventional steady-state analysis, transient simulation over the whole trajectory was found to be crucial and useful for prediction of behaviors unrecognized by steady-state simulations.
Application of an Evolutionary Algorithm in Well Test Characterization of Naturally Fractured Vuggy Reservoirs
Authors: Gómez S. , Fuentes G. , Camacho R. , Vásquez M. , Otero J. M. , Mesero A. , Castillo N. del
Published: December 2007

During the last years, several efforts have been done focused on developing the automatic computer-aided well test analysis. Traditionally, conventional gradient-based algorithms such as Levenberg-Marquardt have been used for parameters estimations. However, recently the use of new approaches based on global optimization methods has been introduced in the literature, mainly attempting to eliminate the influence of the initial guess on the overall regression, and overcoming the uniqueness problems.

The aim of this work is to study the characterization of naturally fractured vuggy reservoirs via the automatic well test analysis by using a triple porosity model recently developed. Thus, an Evolutionary Algorithm (EA) was designed, taking into account the important fact that the triple porosity case may yield multiple solutions. Therefore, several aspects such as the parameters estimations with high precision and the necessity of developing analysis techniques computationally efficient are taken into account in the design of algorithms.

According to the above, it is demonstrated that the algorithm developed in this work allows finding the multiple optimal solutions, with the desired precision. Advantages of the EA over the classical Levenberg-Marquardt method for this specific well test analysis problem are also discussed.
Successful Drilling of Oil and Gas Wells by Optimal Drilling-Fluid Solids Control – A Practical and Theoretical Evaluation
Authors: Dahl B. , Saasen A. , Omland T. H.
Published: December 2007

Since the development of the drilling industry the process has culminated in using shaker screens as the primary or only device for removing drill solids from the drilling fluid. Therefore it is necessary to optimize both filtration efficiency as well as the screen life to hinder drilled solids entering the drilling fluid. Optimum solids control can be obtained by using the understanding on how damage of the filtration cloth arises, on how to reduce it and finally on how the particles in the circulation system influence the general picture of the drilling process. When this knowledge is accepted in the industry, established and implemented in the drilling organisation; it is possible to maintain proper drilling.

This paper describes in detail the theory and field examples on how wear arise on the shaker screen cloth. As will be shown, this knowledge has been used to increase the solids control efficiency at the same time as the screen wear has been reduced by more than 90 % in field cases were 17 ½" sections have been drilled with OBMs. The documentation is based on practical offshore result from these drilling operations including data from the drilling log, laboratory analyses of the drilling fluid and of the Particle Size Distribution (PSD) of the drilling fluid. The particular focus of this article is the application of double deck shakers.
Innovative Design Processes and Technologies Improve PDC Bit Performance in Harsh Drilling Environments
Authors: Mensa-Wilmot G. , Mikhail B. , Al-Saeedi M. , Sounderrajan M. , Al-Anzi D. , Al-Khaldi M.
Published: December 2007

PDC bits are still confronted with performance challenges, especially in hard and/or abrasive formations. In most instances, the bit development or selection process compromises ROP for durability or vice versa. These solutions do not create the types of conditions needed to ensure the expected measurable gains in performance. As such effective product development, which targets the ROP/durability relationship, based on the performance optimization requirements of different applications, must be sought.

This paper will discuss field proven design processes and technologies, which have successfully been used to improve PDC bit performance in harsh drilling environments. The importance and contributions of bit stabilization in this effort, as well as its effects on ROP and durability, will be discussed.

As part of the product development processes that will be presented in this paper, drilling efficiency (DE) will also be discussed. In addition, the effect and influences of bit durability on drilling efficiency will be presented. Field data showing the positive impact of the new process on PDC bit performance, especially in hard and/or abrasive formations, will also be presented.
Experimental Study on Applicability of Water-Alternating-CO2 Injection in the Secondary and Tertiary Recovery
Authors: Nezhad S. A. T. , Mojarad M. R. R. , Paitakhti S. J. , Moghadas J. S. , Farahmand D. R.
Published: December 2007

One of the problems that the world will face in the next future is the reduction of hydrocarbon reserves and the challenge in finding new resources. In recent decades, new ways to improve production methods and enhancing the recovery factor from reservoirs have been attempted.

Considering an increase in the different techniques of improving the recovery processes and the imperativeness of efficient recovery from existing reservoirs whose capacity for producing flow rates have been diminished, brings up the need for further studies and research for developing different methods to enhance oil recovery processes.

The goal of this paper is to investigate the profitability of immiscible water alternating CO2 injection in the secondary and tertiary recovery after water-flooding and continuous CO2 injection at laboratory scale. The experiments were performed in the sand packed model using dead oil sample taken from a southern Iranian reservoir at constant injection pressure (1500 psig) and constant temperature (the reservoir temperature, 190 °F) conditions.

The results indicate that the WAG process using CO2 can be efficient, especially when it is used a secondary recovery process rather than tertiary one.
Use of Amine/PHPA System To Drill High Reactive Shales in the Orito Field in Colombia
Authors: Guerrero X. , Guerrero M. , Warren B.
Published: December 2007

The use of water based fluids replacing oil based drilling fluids has been increasingly being applied in the Petroleum Industry in order to mainly accomplish environmental legislation.

A challenge when using water based drilling fluids in highly reactive shales is to overcome problems such as wellbore instability, torque and drag and environmental requirements. This was the case in the Orito oil field in Colombia.

The Orito field is located to the south of the country and has been operated by Petrominerales Colombia Ltd. During years of exploitation, the Orito wells were drilled with oil base muds in order to address wellbore instability problems related to the highly reactive shales of the Villeta formation, which is drilled in the 311 mm (12 ¼") hole and is about 300 m (1000 ft) long.

Some years ago, different water based mud systems have been used in the area; however, it has not achieved the high performance expected by the operator to successfully drill the troublesome Villeta formation. Thus, in order to drill the two last development wells in the Orito field, it was proposed that an Amine/PHPA system to be evaluated. The Amine/PHPA system has been developed by Q'Max Solutions in Canada and has also been used in Ecuador with very good results.

According to own experiences in the field, the Amine/PHPA system was formulated to achieve the right concentration of each mud product to satisfy the necessity of a system that provides at the same time good inhibition, adequate rheology properties and lubricantion during the angle build section.

Capillary Suction Test (CST) were carried out to determine the right concentration of amine and PHPA to provide inhibition for the highly reactive Villeta shales. Historical cases of hydraulics and operational performance were studied to find out xanthan gum concentrations to reach adequate yield point values that secure hole cleaning during the most critical deviated section of the interval and lubricant concentration was also determined to reduce torque and drag in the water based system.

This paper is intended to present the performance of the Amine/PHPA system and environmental achievements in an environmentally sensitive area. Laboratory and field data obtained during the project is also presented.
Conceptual Model Design Studies for a Self-Sustained and Complete Productive Utilization of High-Viscosity/Extraheavy-Oil Onshore Reservoir in Mexico
Authors: Ascencio-Cendejas F. , Reyes-Venegas O.
Published: December 2007

This paper shows the results of conceptual and feasibility studies for the design of a Self-Sustained and Complete Productive Utilization of High Viscosity-Extra Heavy Oil Onshore Reservoir in Mexico.

An onshore reservoir in Northern Mexico containing extra heavy oils (6-12 API) with extremely high viscosity (>40,000 cp at 20°C) can be exploited in integral and efficient manner in a energy self-sufficient cycle by means of the proper coupling of several components or modules as: injection of CO2 – readily available in the region – into the artificial lift systems.

At the reservoir level the CO2 injection generates foamy Oil with much lower viscosity and density. On the surface the produced heavy oil can be hydrogenated to produce lighter oil with a better economic value and the residual heavy sub product can be feed to a power plant to generate the energy for the production artificial systems and the pumping or compressing equipment for pressure maintenance of the reservoir. Alternative analysis by in-situ enhancement of the oil - by hydrogenation process in the reservoir – is also included as to cover the economic aspects of this integral and energy self sustained extra heavy oil system

Thermally enhanced artificial systems and pressure maintenance of the reservoir (by fluid injection) achieved through novel and clever thermal design, operation and maintenance of the wells, pipelines and process equipment maintains the viscosity of the oil at acceptable level as to keep an efficient deliverability of the fluid to the surface as a foamy oil because CO2 injection. Hydrogenation of the oil in-situ or on surface facilities produce ultra heavy fraction that is feed to a power plant to produce all the energy required in the cycle to allow for self sustaining the field-production-processes.
A General Method for the Flow Diagnosis and Interpretation of Well Tests
Authors: Ascencio C. F. , Samaniego-V. F. , Ley H. C. , Feraud J.-P.
Published: December 2007

This paper presents a new technique for transient pressure analysis, based on a general diffusivity equation for any of the different coordinate systems. Essentially, this method consists in the identification of a flow exponent n for which the pressure resposne graphed in a log-log scale in terms of t1−n|p′(t)| versus t would show a horizontal behavior. It is demonstrated that the value of this exponent corresponds to the flow pattern (diagnosis; for example, linear, radial, spherical, etc., flows ), and the intercept is inversely related to the formation conductivity. For cases of highly heterogeneous formations of fractal propeties, the value of the n exponent could be different from any of the most well known exponenet values (linear;1/2; radial, 0; spherical: -1/2; bilinear: ¼; and pseudosteady state: 1).