bluuebunny/crossref_metadata_2025 huggingface dataset:
Diffusion Coefficient of n-alkanes in Heavy Oil
Authors: Guerrero-Aconcha U. , Salama D. , Kantzas A.
Published: September 2008

The use of hydrocarbon solvents in the recovery of heavy oil has been increased because of the advantages they have over the thermal methods under some reservoir conditions. The injection of a miscible solvent in the reservoir implies a mass transfer process which is governed by a diffusion coefficient. Consequently the measurement of the diffusion coefficient is extremely important. This, however, presents a significant amount of challenges in the laboratory and in the data analysis, mainly because of the viscous and opaque nature of the heavy oil and the dependence on concentration of the diffusion coefficient. The Matano-Boltzmann method has been used in the past to obtain the concentration dependency of the diffusion coefficient of solvents in heavy oil. Although the method successfully shows that such dependency exists, the results exhibit abnormal trends.

In this work the concentration profiles of three n-alkanes in heavy oil were obtained in the laboratory using Computed Assisted Tomography (CAT), and the "Slopes and Intercepts" analytical technique was used to calculate the concentration-dependent diffusion coefficients. The results are in good agreement with the theory of diffusion in binary mixtures. In addition a comparison is presented with the Matano-Boltzmann method. Finally the Vignes model was successfully used to also perform predictions on the studied systems.
Improved Prediction of Oil Recovery from Waterflooded Fractured Reservoirs
Authors: Salimi Hamidreza , Bruining Johannes
Published: September 2008

Simulations of waterflooding in fractured media are based on the Warren and Root (WR) approach, which uses an empirical transfer function between the fracture and matrix block. Arbogast used homogenization to formulate an improved flow model in fractured media, leading to an integro-differential equation; also called the boundary condition (BC) approach. A wellposed numerical 3D model for the BC approach has been formulated. This paper derives this numerical model to solve full 3D integro-differential equations. The results of this model are compared with the ECLIPSE results. For the interpretation it is useful to define three dimensionless parameters, which characterize the oil production in fractured media. The most important of these parameters is a Peclet number defined as the ratio between the time required to imbibe water into the matrix block and the travel-time of water in the fracture system. The results of the WR approach and the BC approach are in good agreement when the travel-time is longer than the imbibition time. However, for times with the same order of magnitude and for the travel time shorter than the imbibition time, the approaches give different results. The BC approach allows the use of transfer functions based on fundamental principles, e.g., the use of a rate dependent capillary pressure function. When implemented, it can be used to improve recovery predictions for waterflooded fractured reservoirs.
Waterflood Surveillance in the Mars Field Deepwater GOM: Mississippi Canyon Block 807
Authors: Weiland Jeff , Mikulencak Duane , Fox Phil , Suparman Suparman , Frisch Gary , Azari Mehdi
Published: September 2008

Waterfloods serve many purposes and their performance can have major economic impact on the drilling, production and management of hydrocarbon reservoirs. The primary purpose of the Mars (Mississippi Canyon 807) waterflood in the deepwater of the GOM is to increase recovery efficiency in three main reservoirs. In addition, the waterflood helps maintain reservoir pressure in selected sands, which minimizes compaction and subsequent well failure.

Surveillance of the waterflood through carbon/oxygen logging, of the formation through compaction logging, and of the individual reservoir layers through multi-rate production logging is critical to the success of the Mars field. The program has consisted of obtaining time-lapse logging and reservoir pressures combined with reservoir modeling. Data has been obtained in the injection, producing, and monitor intervals of several Mars wells and proven to be vital to the evaluation of waterflood efficiency and the prediction of the waterflood front.

A monitoring logging program has been conducted in the Mars area since 1996, with initial baseline surveys, to the present day monitoring surveillance program. The logging program has had two purposes. The primary purpose of the program has been to monitor the "sea water" waterflood saturation fronts with carbon/oxygen logging and integrate this data into the reservoir models. A second purpose has been to monitor strain as a result of reservoir compaction and to monitor the effects of the waterflood on the rate of strain. This data is used to help determine wellbore integrity and ultimately to predict wellbore failure. It also provides calibration data for the compaction model used in reservoir simulation.

Selected Mars well examples are described in detail to highlight the results of time-lapse monitoring of the waterflooded reservoirs. A comparison of log data with simulation modeling predictions demonstrates the benefit of the data acquisition and evaluation methods. Discussion is focused on best practices learned during the 12 year program, how log responses have helped verify modeling parameters, and on justification of future activities.
Implementing i-field Initiatives in a Deepwater Green Field, Offshore Nigeria
Authors: Adeyemi O.S. (Tope) , Shryock S.G. (Steve) , Sankaran Sathish , Hostad O. , Gontijo J.
Published: September 2008

In recent times, i-field, e-field, digital oilfield of the future etc. have dominated discussions focusing on increasing the recovery from both shallow and deep water assets using electronic technologies. The common theme is the ability to integrate tested and emerging information and communication technologies (ICT) with asset management workflows for improved recovery, collaborative decision making and prompt intervention thereby increasing the asset's bottom-line.

A methodology adopted for implementation of i-field in one of Chevron's mega projects is presented in this paper. The Agbami field, located in deepwater offshore Nigeria is a subsea development incorporating crestal gas and peripheral water injection. It is located in ~ 5000 ft of water and consists of a 38 well development program to be implemented in 3 phases. The first phase involves 22 wells – 12 producers, 6 water and 4 gas injectors. The well completion incorporates intelligent well completion (IWC) – downhole flowmeters, pressure & temperature gauges and interval control valves (ICVs). These downhole accessories will be controlled using electric and hydraulic controls/instrumentation with Subsurface, Subsea and Topsides data acquired and transmitted to a central data historian on the FPSO in relevant time.

The implementation of a robust architecture for Data and Information Management System involving acquisition, processing, storage and replication (from offshore to onshore) is conceived to be the bedrock of the other main focus areas namely: Production Optimization, Reservoir Management & Surveillance, Facilities & Equipment Reliability, and Asset Decision Environment. The impacts of these four focus areas and the methodology engaged in identification, prioritization and generation of the relevant workflows have been discussed.

The expected gains from implementing i-field include improved well and facilities uptime resulting in increased efficiency and reliability, increased production, improved ultimate recovery, and better overall performance from automation of several routine activities. This will ultimately increase the expected value (EV) of the asset through better and prompt decision making using appropriate collaborative tools. In addition, best practices and lessons learned for development and deployment of i-field initiatives in a green field environment are presented with possible applications to mature brown fields.
A Simplified Method for Prediction of ECD Increase with Drillpipe Rotation
Authors: Hemphill Terry , Ravi Krishna , Bern Peter , Rojas Juan Carlos
Published: September 2008

The ability to accurately predict the effect of drillpipe rotation on Equivalent Circulating Density (ECD) remains a challenge for those involved in engineering today's complex wells. In many of these challenging wells (extended-reach drilling, deepwater, HPHT, etc.), the safe drilling window between hole collapse and fracturing is often narrow. Accurate prediction of the effect of drillpipe rotational speed could allow better optimization of operational parameters in the drilling process, and hopefully reduce the incidence of violation of the safe drilling window.

Recently ECD results measured at different circulation rates and drillpipe rotational speeds were modeled and presented to the industry. The calculation methods involved several complex factors including estimated drillpipe eccentricity, nonlinear shear rate modeling coefficients, drillpipe geometry correction factors, etc. The presented results constituted the best-available correlation with direct downhole pressure measurements, but still showed improvement was needed.

Further development work has been done in this same area to reduce the complexity of the calculations and yet improve modeling accuracy. It was noticed that the effect of increasing drillpipe rotational speed at a constant annular velocity produced a near-linear increase in ECD. In addition the ratio of the internal diameter of the hole or casing and the outer diameter of the drillpipe (Di/Do) was found to be a meaningful modeling parameter that could transcend explicit values of estimated drillpipe eccentricity. Data from the earlier work and some additional field results were then reworked using the new calculation scheme, which is presented in the paper. The results presented in this paper show that this calculation technique can produce better prediction of field measurements of downhole pressure changes while rotating and is much simpler to use. Not only can it help in navigating through the safe drilling window, but it also can be used to separate pure rotation effects from other coupled wellbore events, such as hole cleaning and barite sag.
Using Nanoparticle Technology to Control Formation Fines Migration
Authors: Huang Tianping (Tim) , Crews James B. , Willingham John R.
Published: September 2008

Various methods have been employed mitigate fines migration problems that result in decreased productivity in oil and gas wells. This paper discusses the use of nanotechnology to fixate the migrating fines using the interaction between the migrateable fine particles present within the formation and nanoparticles associated with a proppant pack treatment. This paper will introduce the use of unique nanoparticles (nanocrystals) for treating hydraulic fracture proppant packs to fixate formation fines.

Nanoparticle technology allows the combining of the extremely high surface area available using these particles, approximately 200 m2 /g, with the surface action of the material to fixate migrateable formation fines. Acting within the proppant bed, this fixation of the fines leads to more stable hydrocarbon inflow by reducing the rapid production decline often resulting from fines migration towards the wellbore. The nanoparticles can be added on-the-fly to hydraulic fracturing fluids to treat proppant just prior to being pumped downhole. The treated proppant pack will then capture and retain migrating fines, thereby preventing them from invading the pack and migrating towards the wellbore where flow impairment could occur.

Laboratory developmental testing is presented to demonstrate the effectiveness of using this unique application of nanoparticle technology and field trials of this application should be completed by September, 2008.
The Future of Fracturing-Fluid Technology and Rates of Hydrocarbon Recovery
Authors: Crews James B. , Huang Tianping , Wood W. Russell
Published: September 2008

A high percentage of oil and gas wells worldwide are hydraulically fractured in order to allow a reservoir to become economically producible and to improve the rate of hydrocarbon production. Annual global investments for hydraulic fracturing are at one billion dollars. Crosslinked polymer fluids are the most commonly used fracturing fluid because of cost and performance criteria. The crosslinked polymer fluids exhibit exceptional performance features to initiate and propagate a fracture, carry proppant and control fluid leak-off into the reservoir during a treatment. However, crosslinked polymer fluids leave a significant amount of polymeric filtercake material in the fracture once a treatment is completed. Decades of improving oxidative, enzyme and other breakers for the polymer fluids has only marginally improved from about 30% to about 50% by weight the amount of polymer residue left within the fracture. The result has been a continuation of much lower than optimum hydrocarbon recovery rates for many wells.

New surfactant-based fluid technology is being developed that will in many geographic regions replace polymeric-based fracturing fluids over the next decade. This paper will introduce a new fluid technology that uses nanoparticles, special internal breakers and low molecular weight viscoelastic surfactants (VES) to achieve the performance features of crosslinked polymer fluids but leaves little to no gel residue. Unique nanoparticles have been found that "pseudo-crosslink" VES micelles together through electrostatic and van der Waals forces. This micelle-networked fluid property will allow unique "pseudo-filtercake" to form on porous media, like crosslinked polymer fluids exhibit, to control fluid leak-off and improve fluid efficiency. The special internal breakers reside within the micelles and go wherever the fluid goes, including the networked micelles composing the pseudo-filtercake. The internal breakers controllably break the viscosity of the VES-based pseudo-filtercake by rearranging the VES micelles to spherical non-viscous structures and dispersed nanoparticles that readily flow back with producing fluids and do not impair the proppant pack conductivity. The primary result will allow a wide range of hydraulically fractured reservoirs to produce at substantially higher sustained rates than presently achievable, particularly for deepwater and other high investment wells.
Completion System Allows for Interventionless Stimulation Treatments in Horizontal Wells with Multiple Shale Pay Zones
Authors: Vargus Greg , Howell Matt , Hinkie Ron , Williford James , Bozeman Tim
Published: September 2008

This paper will discuss case studies and details of a pinpoint stimulation/completion process that uses stimulation sleeve technologies in conjunction with swelling packers as part of an openhole, horizontal, well lateral liner that is anchored by an expandable liner hanger. This system will allow an operator to accurately place several individual stimulation treatments without additional intervention in the wellbore. This is accomplished by installing the closed stimulation sleeves and swellable packers as part of the completion string, (horizontal openhole liner) and positioning the string in the wellbore so that the stimulation sleeves are located within the desired production pay zones. The completion string is then anchored in position with an expandable liner hanger. The swellable packers are allowed to expand for a few days and isolate the zones between each of the sliding sleeves. Stimulation/frac equipment is rigged up, and a series of progressively larger balls are dropped throughout the multistage pumping operation. The balls land on the tapered baffles in the sleeves, each of them opening in sequence and sealing off the previously treated zones below. Once opened, a stimulation sleeve allows pumping a treatment into the zone where it is positioned. After being opened, the stimulation sleeves maintain the capability to be closed and reopened, with minor intervention, with a shifting tool allowing for restimulation or other workover at a later date.

This new service is a field-proven process with 120 wells completed and more than 850 stages/zones treated. This method reduces the time and cost needed to complete multiple intervals in a well, and bring production on line faster by comparison to conventional multizone horizontal fracturing/stimulation techniques such as multiple perforating and setting plugs.
Volatile Phosphorus Free Gellants for Hydrocarbon Based Fracturing Systems
Authors: Lawrence S. C. , Kalenchuk A. C. , Ranicar K. , Dhillon S. , Baig A.
Published: September 2008

In recent years, a number of refineries in Western Canada and the United States have discovered the formation of scale or sludge in their distillation towers. The build up of large amounts of sludge lowers the efficiency of refineries to the point where it must be removed. The process of sludge removal requires that the refinery shut down at a cost of millions of dollars in lost production to the refinery operators. Analysis of the sludge has revealed that it has an extraordinarily high phosphorus content (8 to 12%). Further investigation into the origin of the phosphorus in the sludge raised concerns that chemicals used in hydrocarbon fracturing fluids, specifically volatile phosphorus containing hydrocarbon gellants, are responsible for the refinery fouling. This paper will discuss how the origin of the volatile phosphorus in the hydrocarbon gellants has been determined and how a viable, ultra low volatile phosphorus solution for hydrocarbon gelling has been developed.
Fluid Sampling in Carbonates-Challenges and Best Practices
Authors: Dawoud Ahmed , Zaggas John , Haddad Sammy
Published: September 2008

A heterogeneous carbonate reservoir can be partly evaluated using OH logs but not fully. Even if production testing is used for evaluation, important details can often be overlooked such as individual pressure behavior of thin laminated sections and/or existence of different fluids within the reservoir section itself.

Zonal pressure testing and sampling done with dynamic formation testers will more than often fill in the missing gaps and in fact will contribute into optimizing future testing and production for the field under investigation. This is usually achieved by an initial comprehensive pressure evaluation profiling (to obtain reservoir pressures and mobilities) followed immediately (in most cases same run) with a comprehensive formation fluid sampling program, by the end of which a comprehensive picture of individual streaks of interest, in terms of pressures and fluids, has been formed.

The employment of Dynamic Formation Testers has nowadays become something of a norm, but the challenges faced in harsh environments can sometimes be daunting. These challenges include operations in extremely tight and overbalanced environments, high solid mud systems, distinction and sampling of formation water in WBM environments or oil in OBM systems, high percentages of H2S formations, long pumping times and stations, collecting representative (single phase) fluid samples and of course environments of high pressures and temperatures.

The present paper will discuss the various problems faced with dynamic formation testers in a typical everyday wireline run, in a typical carbonate environment (U.A.E) and discuss a variety of topics that include formation heterogeneity, supercharging, tool options, real-time (RT) monitoring while logging, invasion, thick transition zones and vertical interference tests. Examples and where applicable recommendations to working around these problems are also presented.
Dual-Role of Water-Soluble Metallic Additives on Modifying In-situ Combustion Performance Using Large Activation Energy Asymptotics
Authors: Akkutlu I. Y. , Yortsos Y. C.
Published: September 2008

Unlike other thermal recovery methods, air injection and in-situ combustion produces significant amounts of heat in the reservoir. However, the process is subject to acute external heat loss rates due to high temperature gradients in place. Consequently, reservoir temperatures may be reduced considerably, leading to a deteriorated combustion performance and debilitated field operations. Goal of this paper is to determine under which reservoir conditions the combustion temperatures could be maintained at sufficient levels. Previous investigators have partially addressed this issue using kinetic and combustion tube experiments. In the absence of heat losses, it has been repeatedly shown that water-soluble metallic additives improve the self-sustainability limit of combustion front in oil and sand mixtures. In general, this has been attributed to dual-role of the additives on the combustion performance: (1) kinetics of heterogeneous oxidation reactions inside the combustion front are modified, namely the catalytic effect; (2) specific surface area of the porous medium ahead of the combustion front is increased, namely the fuel deposition effect. It is currently a common belief that appropriate introduction of such materials in a reservoir environment could enhance the performance of combustion process and, hence, improve the recoveries. Determining their role on in-situ combustion performance requires that the mechanisms of combustion are well understood. Complex physical and chemical nature of the problem at the pore-scale has prevented detailed investigations using physical and numerical models, however. Here, we approach the problem analytically using a sequential reaction (HTO/LTO) combustion front propagation model, based on the large activation energy asymptotics, and introducing systematically the reaction kinetics and fuel deposition effects of the additives to the model. Coherent propagation of the reaction regions are then investigated in terms of their temperatures, propagation velocity and the oxygen consumption efficiency. It is found that an improved combustion performance can be observed only if both the kinetics and fuel deposition effects develop under the reservoir conditions.
Theoretical and Experimental Investigation of Water in Oil Transverse Dispersion in Porous Media
Authors: Duan Shengkai , Wojtanowicz Andrew K.
Published: September 2008

Water production is controlled by the size and distribution of water saturation around wells. Reported in this paper is a continuing research into mechanisms causing expansion of the water saturation transition zone (transverse dispersion) in a segregated flow of oil and water approaching a vertical well's completion. The mechanisms – including non-linear (non-Darcy) flow, turbulence, shear rate, flow baffling at grains – all contribute to instability of the oil/water interface resulting in hydrodynamic mixing. Interface instability due to shearing rate has been demonstrated in our recent study on the Hele-Shaw model. In this work, we have evaluated the practical size of the mixing zone around wells, modeled mathematically the effect of flow baffling, and demonstrated transverse dispersion experimentally using a linear physical sand pack.

The maximum size of the mixing zone was evaluated using the turbulence criterion and differential velocity for typical wells' inflow conditions. Critical dimensionless numbers for flow in porous media were used to determine the onset of transverse dispersion. The radial size of mixing zones was then correlated with fluid properties, water cut, and the effective area of well's inflow.

A simple model of "bifurcated flow" was developed to demonstrate the effect of two phase flow baffling in granular porous media. The model shows that the change of flow momentum of the two fluids at collisions with rock grains becomes the major factor causing water dispersion.

A series of segregated (top oil; bottom water) flow runs were carried out using physical model packed with different porous media at a constant pressure drop. The runs were videotaped and analyzed for saturation distribution using a color intensity recognition software. The results clearly demonstrate onset of transverse dispersion of water into the flowing oil. Further dispersion, however, was overshadowed be the dimensional and end-point effects of the model. With a numerical estimation procedure, the initial dispersion rate – computed from the 1-D flow model – is the essential data needed to estimate total dispersion in radial inflow to wells.
Plugging Wells with Hydrated Bentonite, Part 2: Bentonite Bars
Authors: Towler Brian F. , Victorov Herman , Zamfir Gabriel , Ignat Pompiliu
Published: September 2008

Data for the kinetics of the swelling of bentonite bars are shown and measurements for the friction factor between the hydrated bars and steel and plastic pipe are given. The results are compared with a previously derived equation for pressure containment. These results demonstrate that the bars produce a hydrated bentonite that has similar or better pressure containment than other bentonite solutions. Bentonite has long been used for the plugging of water wells and these bars have been produced for use in the plugging and abandonment of oil and gas wells.
Field Trial of a New Non-Damaging Degradable Fiber-Diverting Agent Achieved Full Zonal Coverage during Acid Fracturing in a Deep Gas Producer in Saudi Arabia
Authors: Solares J. Ricardo , Duenas J. J. , Al-Harbi Moataz , Al-Sagr Abdulaziz , Ramanathan Venkateshwaran , Hellman Ryan
Published: September 2008

Acid fracturing has been an integral part of Aramco's gas development strategy for the vertical wells in the Khuff carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. During acid fracturing, the wormholes created by the reaction, results in excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid, a polymer-based system, are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad.

These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest reservoir quality zones with minimal contribution from the other zones in many cases.

Field trials involving the use of a new degradable fiber technology designed to achieve effective acid diversion during acid fracturing was recently implemented. The trials were conducted in a matrix acid and in an acid fracturing treatments, which were designed and pumped with alternating stages of acid and fiber-laden polymer based pad fluid. The significant viscosity increase achieved in the pad by the addition of fibers and its particulate bridging mechanism would plug off the just stimulated zones effectively, thus diverting the new stage of acid into the non-stimulated porous zones. These fibers degrade and hydrolyze with temperature and time thus leaving the reservoir undamaged.

This paper discusses the planning and design processes leading to the successful implementation of the technology, the experience during the stimulation treatment execution and the excellent post-stimulation results. A production logs was run in the acid fractured well to ascertain the effectiveness of the technology. The results are discussed and compared in the paper with those from offset conventionally acid fractured wells, and the lessons learned throughout the pilot are also shared.
Design of Improved High-Density, Thermally-Stable Drill-In Fluid for HTHP Applications
Authors: Ezell Ryan , Harrison Douglas J.
Published: September 2008

As we approach an age of deeper discovery and petroleum producing wells with hostile environments, the industry need for an elevated-temperature, high-density, low-solids, and non-damaging reservoir drilling fluid or "drill-in fluid" has moved to the forefront of laboratory and applied research. Drill-in fluids are a special class of drilling fluids that prevent formation damage, provide superior hole cleaning, and help minimize wellbore cleanup effort, resulting in increased efficiency from the production reservoir. These fluids address the wide range of difficulties encountered in horizontal drilling, completion, and workover operations.

The need for fluids with service temperatures above 300°F has increased beyond the capabilities of traditional biopolymers to create rheologically stable fluids. While some water-based drilling fluids excel at these higher temperatures, their formulations include non-acid soluble solids that are damaging to hydrocarbon-bearing formations and hence undesirable. With higher temperature reservoirs being drilled, there is need for a suitable high-density, high temperature stable drill-in fluid.

For the development of the fluid presented in this work, various high density brines were evaluated to achieve fluid weights up to 17.6 ppg (2.1 sg) in order to reduce the amount of weighting agent utilized in the system since these solids can result in high plastic viscosities and create difficulty in the cake removal and clean-up processes. The total amount of CaCO3 bridging material was maintained at a relatively low concentration to produce a thin, acid-soluble filter cake while the bridging particle size was determined by the ideal packing order of the chosen pore size.

The improved drill-in fluid was shown to possess thixotropic fluid rheology. Its additives are based solely on synthetic polymeric material for increased chemical and thermal stability. Hot-roll temperatures in excess of 355°F (180°C) were achieved with no loss in rheological properties.
Maximizing Hole Enlargement While Drilling (HEWD) Performance With State-of-the-art BHA Dynamic Analysis Program and Operation Road Map
Authors: Algu D. R. , Denham Waitus , Nelson Gail , Tang Wei , Compton Molly T. , Courville David F. , Fitzmorris David L.
Published: September 2008

Hole enlargement while drilling (HEWD) is an important technique in both deepwater and onshore drilling. Drilling interbedded formations is a difficult HEWD application. Two extreme cases can occur. One case is when the reamer drills in soft formation while the bit is in a harder formation. The other more difficult situation is when the reamer is in a hard formation while the bit drills ahead in soft formation. The latter creates an enormous challenge for the reamer to drill the harder formation without inducing large lateral and torsional vibrations which is detrimental to the reamer and other BHA components. An overall HEWD operating parameter management approach can greatly reduce probabilities of tool damage and unnecessary tripping while dramatically reducing drilling costs.

A state-of-the-art BHA dynamic analysis program that allows modeling the reamer and bit in different formations plays a vital role in the overall HEWD management process. Before any planned HEWD operation, various possible operating scenarios can be virtually simulated through the BHA dynamic analysis program to evaluate the effect on BHA components of lateral and torsional vibrations. An optimized BHA configuration can be specified through these analyses and a set of optimal operating parameters for the chosen BHA can be developed.

This paper presents an excellent case study of HEWD through severely depleted interbedded formations in the Gulf of Mexico. Previous offset wells had required multiple runs to HEWD this section due to reamer cutting structure damage. Models were constructed to compare performance with a range of BHA, WOB/WOR and RPM combinations. A set of optimal operating parameters and a road map were established for managing these parameters on the rig. Most importantly, the analyses recommended operating conditions that were substantially different from the accepted HEWD operation of increasing weight on bit (WOB) in harder formations. The analyses indicate that overall BHA performance was dramatically affected by weight on reamer (WOR). With a small sacrifice of ROP in the harder, more abrasive formations the HEWD system can effectively drill through the entire section without tripping due to component failure. This approach achieved excellent overall cost effective performance saving the operator $1.89 million on an offset well.
Knowledge Management and Preparing for the Big Crew Change—A Fresh Approach
Authors: Kulakofsky David
Published: September 2008

Achieving consistent long-term zonal isolation via the hydraulic cementing process is a worldwide challenge that can benefit from experienced personnel. Each well type presents a specific set of complexities that require assessment and technical problem solving. Under today's massive industry-wide hiring blitz, an ever increasing portion of the work is being done by personnel with fewer years of experience than in recent decades. It is critical that a methodology be made available to transfer best practices down to the frontline and capture the knowledge of experienced personnel likely to retire in the next 10 years. While many of the associated operational tasks have well-documented procedures, the engineering and job design have aspects that have not benefited from the same degree of documentation to capture step-by-step guidelines or process mapping.

In an effort to secure for future reference all of the industry's current cementing job design and engineering knowledge and best practices, an entire library of technical playbooks has been created. While these playbooks specifically address issues related to cementing, the methodology for securing and referencing the expertise is equally applicable to the industry's other specialties. This paper contains a discussion of the methodology used to develop these playbooks, as well as examples of how they are used to increase both reliability and innovation, including their applicability to the industry as a whole.
The Benefits of Safety Card Automation in Behavior-Based Safety Systems
Authors: Kaminski Donald , Graf Jake , Fortune Dan , Toups John
Published: September 2008

One of the more significant problems with Behavior Based Safety (BBS) Observation systems is the management of information, including the input of data into a repository, and the extraction of tangible outputs and actionable issues in a timely manner. BJ Services Company and JW Toups, Inc. have collaborated on the development, testing and implementation of a scannable system that captures BBS observations and interventions. The system allows the end user to scan hundreds of BBS cards and run reports on leading indicators within days. The system outputs trending data in an easy-to-read pie chart format for review in safety meetings and posting on bulletin boards. The scanning aspect of the system reduces both input time and administrative cost. A cost reduction of as much as 40% can be realized depending on current input techniques. In addition, the system automates the notification of management when the person completing the observation indicates management needs to take action. Management is then able to react more quickly and with a focus on the issues that really matter. This quick response increases employee participation in the BBS process. The pilot location reported an increase in participation of 30% when comparing subsequent quarters. The system solves the issue of managing information by providing management the tools to determine leading indicators and actionable items quickly and efficiently that, when addressed, make a safer workplace.
Advanced Cement Systems Used to Improve Geothermal Well Reliability in Java
Authors: Ravi K. , Fukuzawa M. , Hunter W. J. , Noerdin A. Isvan
Published: September 2008

An operator developing a geothermal field to generate and provide electricity in Indonesia focused on minimizing the potential for failure of planned wells throughout the expected field life. One of the main areas where this effort was directed was in the design and execution of primary cementing jobs during well construction. Wells drilled and completed earlier, in Phase I, were found to suffer from various wellbore integrity issues. Inspection log data and cement job records from existing wells suggest the zonal isolation problems experienced on earlier wells may have been related to (1) structural failure of the conventional cement sheaths used and/or (2) ineffective cement slurry placement caused by poor hole cleaning of the drilling fluid and/or (3) ineffective removal of drill cuttings from the well during the hole cleaning.

Structural damage to the cement sheath can sometimes be in the form of debonding at the casing, formation interfaces, cement sheath cracking, and/or compressive shear. The damage can be caused by stresses on the cement sheath brought on by well events such as cement hydration, well completion, and steam production. These events change the temperature and pressure under which the cement slurry is placed and cured. If these changes are severe, the cement sheath may be damaged, leading to zonal isolation failure.

After detailed analysis, and by using an integrated design approach to effectively address the challenges identified, it was decided to use innovative elastic cement systems incorporating various mechanical property enhancement additives expected to withstand the predicted well operations with less possibility of failure than conventional cements.

These advanced cement systems were placed in the planned development using conventional cementing equipment. Industry-recognized best practices were also used to maximize mud displacement and enhance hole cleaning. These wells were steamed, and no wellbore integrity issues have been reported. Additional benefits observed while using the advanced cement systems in these applications include a reduction in lost circulation and significantly reduced wellhead growth.
Pseudo–Compositional Model for the Calculation of Liquid Viscosity in Oil Production Systems
Authors: Bergman David F. , Sutton Robert P. , Zaghloul José
Published: September 2008

Modern numerical simulators can couple models to represent the behavior of reservoir, wells and surface facilities. This has created a need for a method to calculate viscosity over a wide range of compositions, pressures, and temperatures. Current compositional viscosity models cannot predict viscosities over these wide ranges. Bergman and Sutton (2006, 2007a, 2007b) published three new correlations that matched viscosity changes with temperature and pressure. Their correlations were based on typical black-oil model parameters; among them solution gas-oil ratio, mole weight and API gravity of the stock tank oil. These parameters change with liquid composition. This paper provides a method for estimating these parameters from liquid composition for calculating viscosity using the Bergman-Sutton correlations. Comparisons with other compositional viscosity models were made to show the new model's improved behavior.
Non-Iterative Phase Behavior Model with Application to Surfactant Flooding and Limited Compositional Simulation
Authors: Roshanfekr M. , Li Y. , Johns R. T.
Published: September 2008

Hand's method is typically used to empirically calculate the equilibrium compositions for ternary systems between two liquid phases. Oil field application of Hand's method is generally limited to surfactant phase behavior with oil and brine, primarily because the excess oil and brine phases are nearly immiscible. Hand's method is not accurate to represent liquid-vapor equilibrium, especially as oil and gas become miscible. It also requires iterations, which means that convergence can be slow depending on the initial guess.

In this paper, we present a new empirical phase behavior model to replace Hand's method. The new method is faster and more accurate, and applicable for both surfactant phase behavior and liquid-vapor equilibrium. The new approach is noniterative and always finds a tie line or its extension even for the limiting tie line at the critical point. Our approach transforms tie lines to a new compositional space, where all tie lines become parallel. Equilibrium compositions are then easily determined in the transformed space. Besides improved accuracy and robustness, the flash calculations for ternary systems show that the new method is up to 100 times faster than conventional calculations using a cubic equations-of-state (EOS), and seven times faster than Hand's method. When incorporated in a compositional simulator, the new method reduces flash calculation time to nearly zero compared to the solution of the pressure/compositional equations. Thus, speedup is proportional to the fraction of time occupied by flash calculations within the simulator. For example, if flash calculations are 50% of total simulation time, speedup is nearly a factor of two using the new approach. This approach is ideally suited for fast recovery estimations for miscible gas floods, and fills the gap between standard or modified black-oil models and fully compositional simulations.
Development and Installation of a Triple Wellhead on the Britannia Platform
Authors: Matheson A. Elizabeth , Tayler Peter , Nash R. Scott , McAuley John
Published: September 2008

The Britannia field is a gas condensate accumulation in the U.K. Central North Sea. The Britannia platform has 36 slots and was initially developed by single wells drilled from 25 of those slots. In 2003 the first of 8 double wellheads was installed enabling two wells to be drilled from each slot (16 wells). In September 2006 the first triple wellhead was installed and three 13⅜ in casings were batch set at 3650 ft TVD. During 2007, three production wells were successfully drilled and completed from this triple wellhead.

This paper discusses the development and installation of the triple wellhead system utilising the experience and lessons learnt from the double wellhead system. Essential to the triple design was that there should be no reduction in hole/casing size, well step out, tubing size or Christmas tree bore size and therefore no drilling or production restrictions for a triple well compared with other wells on the platform. A design/implementation team was set up with operator personnel, contractor personnel and various service providers. This paper discusses the challenges faced by the team – design of the wellhead and tree, running 38 in x 46 in flush joint conductor, running the internal well splitter system on 5½ in tubing and checking its alignment, running of the casing starter head from the production deck, the modelling and clash checking work done to ensure that the wellheads, trees and flowlines would fit in the space available and having the ability to perform wireline work on one or two of the triple wells when drilling on another.

The design objectives were all met and in early 2007 an extended reach well measuring 21580 ft with a step out of 16300 ft was the first well drilled and completed from the triple slot. The second well was a 14100 ft infill well and the third well in the triple slot was completed in November 2007 with a measured depth of 17680 ft MD and a step out of 9970 ft.
Magnetic Resonance in Chalk Horizontal Well Logged With LWD
Authors: Thorsen Arve K. , Eiane Tor , Thern Holger , Hughes Baker , Fristad Paal , Williams Stephen
Published: September 2008

This paper describes geological and petrophysical evaluation of a new structure of a mature field to evaluate the reservoir potential in un-produced reservoir zones. The well was drilled in a carbonate with variations in rock quality and with minor sub-faulting occurring. Gamma, Resistivity, Density, Neutron, and Image services were used in the horizontal part of the well in addition to Magnetic Resonance. To achieve the best possible real-time wellbore placement, reservoir navigation and continuous follow-up on the horizontal log interpretation was performed during drilling.

For the first time a low gradient Magnetic Resonance (MR) while drilling technology was deployed in a virgin carbonate horizontal well on the Norwegian Continental Shelf. The MR Service was run to obtain porosities (incl. partitioning of movable and bound fluids), HC saturations, and permeability estimates. Fluid saturations based on traditional methods and the MR were evaluated and compared by core data, enhancing the understanding of the measurement and the reservoir. For post-processing the MR data were integrated and interpreted together with the other measurements performed in the well delivering an accurate and consistent reservoir description.

First part of the horizontal part of the well was drilled with conductive drilling fluid and the latter part with non-conductive drilling fluid. Lab measurements for the two mud filtrates were performed to understand the influence of the two different drilling fluid types on the MR measurements. In the absence of oil based mud filtrate invasion, the MR data show better agreement with saturations from core confirming the quality and reliability of the MR data.

Comparison of the MR T2 distribution and volumetric with image data indicates that even fine variations in rock quality and lithology are reliably resolved by the MR data. Prior to logging, old core data was used to refine the constants used in the Timur-Coates MR permeability equation. MR permeability showed changes in reservoir quality. Values will be calibrated when Timur-Coates constants are derived from the core plugs from this well.
Actual 3D Shape of Wellbore Trajectory: An Objective Description for Complex Steered Wells
Authors: Liu Xiushan , Samuel Robello
Published: September 2008

All conventional methods for calculating the trajectory of a wellbore involve assumptions. Most calculations assume that segments of the trajectory can be approximated as straight lines, polygonal lines, cylindrical helixes, circular arcs, or combination of these approximations. Conventional methods calculate the course coordinates of a well survey interval according to the predetermined shape for the trajectory. But, what does the real shape of a trajectory in each surveyed interval really look like? Why? What parameters play decisive roles in determining the true shape of a surveyed interval? Is it reasonable to assume that every survey interval has the same kind of approximate shape? Until now, the drilling industry has not found satisfactory solutions to these questions.

This paper presents the results of research about the true shape of a wellbore trajectory relative to its survey stations. It also provides a universal equation for a wellbore trajectory in a surveyed interval and presents an objective approach for describing and calculating a wellbore trajectory in space. The new method does not assume that the shape of wellbore trajectory is a set of typical approximations. The study shows that the wellbore curvature and torsion at survey stations determine the shape of the wellbore trajectory at subsequent intervals, and that 3D coordinates of wellbore trajectory in a local coordinate system are linear, quadratic, and cubic functions vs. curve length, respectively. The new method yields a continuous wellbore trajectory. Extensive simulations have been carried out and are reviewed in this paper. The paper compares the results predicted by mathematical simulation using the new method with actual, observed trajectories and describes the results from other methods to show the accuracy of the new, improved method. The new method shows excellent precision in calculation and reliability.

This study has also proved that the minimum curvature method and the natural curve method, the most commonly used methods, are related to the new method.