bluuebunny/crossref_metadata_2025 huggingface dataset:
Combining SBM Modeling and Drilling Data to Elucidate GOM Well Problems
Authors: Iyoho A. W. , Kunning J. R. , Oskarsen R. T.
Published: December 2007

This paper discusses a field-applicable wellbore hydraulics simulator for modeling cement displacement using SBM (synthetic-based mud) inside casing strings, and calculating ECD (equivalent circulating density) and SPP (standpipe pressure) while drilling with compressible mud. The paper shows how drilling data and model results can be used collaboratively to improve the understanding and solution of well problems. The spreadsheet-based simulator consists of readily available models designed to describe the behavior of SBM under typical conditions encountered in deepwater GOM (Gulf of Mexico) operations. The algorithms account for water depth, pressure, temperature, mud composition, viscosity, wellbore size, and cuttings loading throughout the wellbore.

Field tests in straight holes where PWD (pressure-while-drilling) tools were run show good results. Typical errors between calculated and measured ECD were In the casing cementing study, measured cement displacement volume to bump the plug compared favorably with model predictions, after proper considerations of compressibility. Applications to high-angle wells require some adjustments.
Perforation Morphology and the Onset of Sand Production
Authors: Walton Ian C. , Chang Frank F. , de Cardenas Jorge Lopez
Published: December 2007

In cased-hole completions the perforations constitute the essential link between the wellbore and the reservoir. Weak formations are often prone to sand production during or immediately after perforating. The industry has developed a range of techniques to either control or prevent sand production, including sand screens, gravel packs, frac-packs and screenless completions, and oriented. Selection of the appropriate technique depends on rock properties, in situ stresses and an estimate of cost and risk of sand production and potential remedial interventions. To make better-informed decisions one must understand the mechanism by which sand is produced into the wellbore and this in turn is dependent on the morphology of the perforation tunnel created in the formation.

This paper reports on experiments undertaken in Schlumberger's perforating laboratory in which shaped charges are fired into rock samples under stress conditions typical of those down hole. Using rocks of various different strengths we are able to categorize the perforation tunnel morphology as competent, rehealed (closed), failed or collapsed depending on the in situ conditions and the perforating designs. This morphology is a primary determinant of the risk of sand production and is the starting point for developing mechanistic models of the sand production process.

Transport of failed rock fragments into the wellbore is dependent on the flow rate of reservoir fluids through the perforation. In the laboratory experiments the pressure in the wellbore adjacent to the perforations is measured with a highspeed pressure gauge, from which the surge flow rate is calculated. We have discovered that surge flow rates are most intense during the first second after detonation of the shaped charge and it is therefore at this time that the formation is prone to sand failure.

In the paper we present details of the experimental program including analysis of the perforation morphology and the wellbore pressure profiles during perforating.
Deepwater Core Comparison with Answers from a Real-Time Petrophysical Evaluation
Authors: Poulin M. , Hidore J. , Sutiyono S. , Herron M. , Herron S. , Seleznev N. , Grau J. , Horkowitz J. , Chabernaud T.
Published: December 2007

Rapid petrophysical evaluation is critical in such expensive venues as the deepwater Gulf of Mexico. Recently, a real-time petrophysical analysis program was introduced based on the combination of elemental concentrations from spectroscopy and standard triple-combo logging1. The application consists of a spectroscopy-based quantitative lithology consisting of total clay, sand, carbonate and pyrite2. Elemental concentrations are used to correct neutron and density for matrix effects3 to directly compute total porosity and to correct for lithology and thereby enhance neutron-density crossover in the case of gas. Intrinsic permeability is computed from the lithology and total porosity using the k-Lambda approach4. Water salinity is input and water saturation is computed using the Waxman-Smits-Thomas equations and porosity and lithology5,6. Finally, irreducible water saturation is computed from the Coates-Timur7,8 equation using the calculated porosity and permeability.

This rapid, automatic petrophysical interpretation has been applied to data from a cored well in the deepwater and comparison with core data demonstrates the validity of the porosity, permeability, and saturation evaluations. Computed total porosity is in very good agreement with core values. Computed permeability is generally within a factor of three of measured permeabilities. Computed water saturation is also in good agreement with core values, partially due to the use of oil-based mud.

However, in spite of the accurate petrophysical evaluation, the interpretation was initially suspect due to a significant discrepancy between the computed clay content and the core values measured by x-ray diffraction (XRD). XRD clay averages less than half of the values computed from spectroscopy using the default subarkose model. In order to investigate this discpreancy, twenty plugs were analyzed for major and minor element chemistry and for mineralogy by dual-range Fourier Transform Infrared (DRFT-IR). DRFT-IR mineralogy is independently validated by comparison with chemistry and is in good agreement with wireline computed total clay. Finally, these DRFT-IR and chemistry data are used to produce an optimized total clay from chemistry model that can be used in existing or future wells in this field with spectroscopy data.
Decision Granularity: Preserving Uncertainty Information in Data Consolidations
Authors: Allan Paul D.
Published: December 2007

While risk analysis and stochastic considerations are widely applied in the analysis of individual projects or wells, frequently this information is lost or misrepresented when data is rolled-up at a division or corporate level. Strategic plans or capital allocations based on the consolidation of expected value descriptions mask the range of uncertainty and performance probabilities inherent in these decisions.

The techniques and mathematics involved in stochastic aggregation are relatively well known, yet not widely applied in corporate planning organizations due to time constraints, data availability, available tools, or data management issues. In many cases, planning organizations rely on historical averages or consolidations of specific scenarios to gain insight into their business uncertainty. These may provide useful insights into the business, but can oftentimes be misleading. Changes to the portfolio over time may make historical assumptions invalid and an aggregation of a specific scenario may represent a possible but highly improbable outcome.

This paper describes a simple method for stochastically aggregating projects, preserving uncertainty information as data is rolled up to a division or corporate level. Case study data and computer modeling will be used to demonstrate the benefits of accurately reflecting stochastic data in aggregations and the problems associated with relying solely on expected value descriptions. The techniques and methods described in this work provide a means for better matching decision granularity (the level at which decisions are made) and the underlying data (the level of data consolidation).
Maximizing Economic Return by Minimizing or Preventing Aqueous Phase Trapping During Completion and Stimulation Operations
Authors: Davis Brian "BJ" , Wood William D.
Published: December 2007

Hydrocarbon exploration continues to evolve toward lower quality reservoirs, particularly in North American natural gas reservoirs. In most cases, without hydraulic fracture stimulation treatments, many wells would have no hopes of being economic plays due to inadequate production volumes relative to the costs associated with drilling the wells. Many of these reservoirs are described as "water-sensitive", but are water-sensitive due to aqueous phase trapping rather than due to clay expansion or salinity shock issues. Aqueous phase trapping is a capillary imbibition effect which has been noted in both oil and gas reservoirs, and has been observed as a particularly severe problem in reservoirs where a sub-irreducible water saturation exists. Understanding the aqueous phase trapping phenomenon is important to the oil and gas industry due to its being the driving force behind many low-permeability reservoir stimulation decisions, which are aimed at reducing the impact of aqueous phase trapping.

Diagnostic tools that utilize measured reservoir parameters are presented for use in evaluating a suspect reservoir's sensitivity to aqueous phase trapping. This paper details primary stimulation options designed to prevent production losses related to relative permeability decreases caused by aqueous trapping. Remedial treatment options where prior well treatments or production losses indicate aqueous trapping are also outlined. An example reservoir and current stimulation techniques are also described, where techniques used to reduce aqueous phase trapping problems are proving successful.
Predicting and Mitigating Erosion of Downhole Flow-Control Equipment in Water-Injector Completions
Authors: McCasland Mark , Barrilleaux Mark , Gai Huawen , Russell Ronnie , Schneider David , Luce Tom
Published: December 2007

Several large projects currently being developed will require high rates of water injection to sustain field life. Several operators are considering installing DownHole Flow Control (DHFC) equipment in these wells. The effects of erosion on this type of equipment could be catastrophic. Erosive effects must be accurately predicted in order to properly design equipment that mitigates them and ensures a long service life.

To do so, BP and Baker Oil Tools performed a joint test program based on a likely injection program for fields in the Gulf of Mexico. The water injection program studied required an injection rate of 45,000 bbl per day in each well. The expected field life was set at 15 years, which meant that up to 250 million bbl of water could be injected into each well. The predicted solids content was around 1 lb per 1,000 bbl, or approximately 250,000 lb over the life of the well.

This paper presents the study undertaken to predict and mitigate erosion effects under these injection conditions. Predictive studies using tools such as Computational Fluid Dynamics (CFD) software are discussed. These studies were used to change the physical geometry of the sleeves to minimize fluid velocities and erosive effects. Finally, a full-scale test of the newly designed equipment was conducted to determine the accuracy of the predictive model. The results also determined whether the configuration would minimize erosion to acceptable levels. The results of this testing are presented as well.

Commentary on the predictive capability of software modeling and analysis of the test results is included. Opinions are given on the impact this study has on the future deployment of DHFC systems in these applications.
Oilfield Environment-Induced Stress Corrosion Cracking of CRAs in Completion Brines
Authors: Stevens Richard , Ke Mingjie , Javora Paul H. , Qu Qi
Published: December 2007

Failures, due to stress corrosion cracking (SCC), of corrosion resistant alloy (CRA) production tubing or sand control screens have been reported in recent years. Increased use of CRA materials for downhole applications is the result of stringent requirements for high-temperature high-pressure and sweet/sour production environments, and competitive cost and availability of CRAs. Most SCC failures are related to the use of high strength CRA materials. Field observations and laboratory tests indicated that SCC of high strength CRAs was strongly related to the demanding environment in which the CRA tubulars were exposed. Oilfield environments such as the properties of associated fluids, temperatures, acid gases, types of CRA, and mechanical demands, to name a few, have been found to have a significant impact on the SCC process.

This paper presents comprehensive results from SCC evaluations of various CRA materials under different oilfield environments. The impact on SCC of different types of CRA materials for a range of temperatures, completion fluid compositions and additives was studied. SCC was also evaluated under various CO2 and CO2/H2S pressures in order to determine the stress corrosion cracking potential of CRAs. Discussion of the best practices for field applications, including on-site monitoring, control of pH and oxygen contamination, as well as other chemical additives, will be presented. These results and discussion are significant in identifying environmental factors directly related to oilfield SCC failures and in selecting best completion practices.
Developing Vertical Column Induced Gas Flotation for Floating Platforms Using Computational Fluid Dynamics
Authors: Lee Chang-Ming , Frankiewicz Ted
Published: December 2007

Vertical column flotation technology has been developed specifically for service on floating platforms. The technology was developed using a combination of Computational Fluid Dynamics (CFD) simulation and physical testing. The time and cost to develop the new technology was substantially reduced through the use of CFD simulation. The development program culminated in the installation and successful operation of a 10,000 barrels of water per day (BWPD) column flotation unit on a spar in the Gulf of Mexico.

CFD simulations were used to optimize the distribution of process fluids and gas bubbles in the column flotation cell and to define a strategy for skimming oil from the flotation cell while the unit was in motion on a floating platform. The result was a column flotation unit design that sweeps each volume of produced water with 150 – 300 micron gas bubbles 400 – 700 times per minute during a 4-minute contact time and permits effective oil skimming even in rough seas. Field performance data is presented for the column flotation cell that is operating successfully on a spar in the Gulf of Mexico.
New Transfer Functions for Simulation of Naturally Fractured Reservoirs with Dual Porosity Models
Authors: Sarma Pallav , Aziz Khalid
Published: December 2007

This paper discusses new techniques for the modeling and simulation of naturally fractured reservoirs with dual porosity models. Most of the existing dual porosity models idealize matrix-fracture interaction by assuming orthogonal fracture systems (parallelepiped matrix blocks) and pseudo-steady state flow. More importantly, a direct generalization of single-phase flow equations is used to model multi-phase flow, which can lead to significant inaccuracies in multiphase flow behavior predictions. In this work, many of these existing limitations are removed in order to arrive at a transfer function more representative of real reservoirs.

Firstly, combining the differential form of the single-phase transfer function with analytical solutions of the pressure diffusion equation, an analytical form for a shape factor for transient pressure diffusion is derived to corroborate its time dependence. Further, a pseudo-steady shape factor for rhombic fracture systems is also derived and its effect on matrix-fracture mass transfer demonstrated. Finally, a general numerical technique to calculate the shape factor for any arbitrary shape of the matrix block (i.e. non-orthogonal fractures) is proposed. This technique also accounts for both transient and pseudo-steady state pressure behavior. The results were verified against fine-grid single porosity models and were found to be in excellent agreement.

Secondly, it is shown that the current form of the transfer function used in reservoir simulators does not fully account for the main mechanisms governing multiphase flow. A complete definition of the differential form of the transfer function for two-phase flow is derived and combined with the governing equations for pressure and saturation diffusion to arrive at a modified form of the transfer function for two-phase flow. The new transfer function accurately takes into account pressure diffusion (fluid expansion) and saturation diffusion (imbibition), which are the two main mechanisms driving multiphase matrix-fracture mass transfer. New shape factors for saturation diffusion are defined. It is shown that the prediction of wetting phase imbibition using the current form of the transfer function can be quite inaccurate, which might have significant consequences from the perspective of reservoir management. Fine grid single porosity models are used to verify the validity of the new transfer function. The results from single block dual porosity models and the corresponding single porosity fine grid models were in good agreement.
Monitoring Alternating CO2 and Water Injection and Its Effect on Production in a Carbonate Reservoir Using Permanent Fiber-Optic Distributed Temperature Systems
Authors: Brown G. , Carvalho V. , Wray A. , Smith D. , Toombs M. , Pennell S.
Published: December 2007

This paper describes the use of fiber-optic distributed temperature systems to monitor the effect of water-alternating-gas (WAG) injection on production from several wells in a Texas carbonate reef reservoir.

Cogdell is an old reservoir re-activated by using alternating injections of water and carbon dioxide (CO2) as the tertiary recovery mechanism. Complex geology makes it necessary to monitor both injection and production over time to determine the effectiveness of the sweep.

Fiber-optic distributed temperature monitoring systems are installed on one injector and four producers, in a six-spot pattern, for continuous monitoring across the crest of the reservoir. Conventional production logging is not possible because electrical submersible pumps restrict access, and repeated injection logging required to monitor changes with the same resolution during several WAG cycles, would be impractical.

Continuous distributed temperature monitoring of the injector enabled a quantitative analysis of the injection profile. This continuous profile monitoring process identified the zone taking the majority of the injected fluid and indicated that injection into the other zones varied with the WAG cycle.

Producer monitoring allowed us to identify the flow contribution from each interval as well as changes over time. CO2 entry was also identified. This information confirmed sweep paths from the injector to the producers and provided an improved understanding of the operation of the WAG flood in the Cogdell reservoir.

The results showed fiber-optic distributed temperature monitoring provided important information for well and pattern performance analysis in wells where our prior ability to monitor response was limited or non-existent.
Alberta Multiwell Micro-Pilot Testing for CBM Properties, Enhanced Methane Recovery And CO2 Storage Potential
Authors: Mavor Matthew J. , Gunter William D. , Robinson John R.
Published: December 2007

The Alberta Research Council (ARC) is performing a project entitled "Sustainable Development of Coalbed Methane; A Life-Cycle Approach to Production of Fossil Energy" that is funded by an international consortium of companies. The main objectives of the project are to reduce greenhouse gas emissions by subsurface injection of CO2 into deep coalbeds and to enhance coalbed methane recovery and production rates. We have performed extensive field tests that includes efforts on two wells located near the towns of Fenn and Big Valley in Alberta that penetrated Medicine River (Mannville) coal seams. This paper presents test procedures, quantitative data measured during this effort, and the interpretation thereof. The evaluation was completed over three years ago and was based upon procedures described previously.1 These data have allowed complete characterization of the coal seam properties with new insights gained into the behavior of coal seams, the volume of natural gas that can be produced, and the volumes of CO2 that can be sequestered in this area.

The fieldwork began by reentering the Gulf Canada (now ConocoPhillips) well FBV 4A-23-36-20 (FBV 4A) well. We conducted a series of single well micro-pilot tests. We began by production and shut-in testing to obtain estimates of the reservoir pressure and permeability before CO2 injection. A CO2 injection test was followed by a shut-in test to insure that CO2 injection was possible. We then injected over 91,500 m3 of CO2 vapor in 12 separate injection cycles. Although CO2 reduced the absolute permeability, injectivity actually increased. The CO2 was allowed to soak into the coal and we returned the well to production. Post-injection testing allowed us to determine the CO2 sweep efficiency as well as the ECBM and CO2 storage potential. Fourteen months later, we injected 83,500 m3 of flue gas using underbalanced drilling equipment that was followed by a post injection-production test.

A second well (FBV 5) was drilled 487 m north of the first well. FBV 5 was cored and logged for reservoir property data. The well was then cased and completed in one Medicine River coal seam. A combination of production tests and water-injection falloff tests were conducted to determine original reservoir pressure, permeability, and gas composition. N2 injectivity tests were performed before injecting 75,483 m3 of a 53%-47% mix of N2 and CO2. The gas mixture was allowed to soak into the coal and the well was returned to production.

All of the post-injection production tests of both wells included detailed measurement of pressure and temperature conditions as well as gas composition variations vs. time. These data allowed us to determine the changes in permeability caused by the injected gas, to estimate possible hydrocarbon sweep efficiency, and possible CO2 storage volumes.
Offshore Processing Options for Oil Platforms
Authors: Bothamley Mark
Published: December 2007

An examination of the various processing options that have been implemented on previous (and recent) offshore oil field developments indicates a very broad range of possibilities. The spectrum ranges from:

Minimal offshore processing with all produced fluids sent to an onshore terminal (or terminals) for final processing to meet saleable product specifications, to Full processing offshore to make specification products on the offshore facility, with no further onshore processing required.

The decision as to where a given project ultimately ends up on this spectrum can have significant implications. For example:

– is the offshore platform small and simple or large and complex? – is an onshore terminal (or terminals) required for final processing or not? – does the gas export pipeline operate in multiphase, moderate pressure single phase, or high pressure dense phase? – what is the impact on project schedule and manning requirement? eg. offshore platform size and complexity, number of facilities - offshore only or both offshore and onshore? – what is the impact on subsequent future projects?

There is little published information or guidelines as to how to make the onshore/offshore processing split decision. Often it is fairly obvious based on the proximity to existing infrastructure (developed areas). In other cases, eg. new offshore regions with minimal infrastructure, it is not. In this regard, the various major offshore producing areas around the world, eg. the Gulf of Mexico (GoM), North Sea, etc., have often taken different approaches. Even in these established regions, there are significant variations in processing scheme details, from facility to facility and between operating companies.

In order to begin to address the "optimum" offshore/onshore processing split issue, it is necessary to first gain an understanding of what the options actually are. The purpose of this paper is to review the main processing options available for an offshore oil production facility, including comparisons, major factors, pro's and con's, etc. This information can serve as a basis for evaluating processing alternatives for future projects.

The Gulf of Mexico and North Sea are large, well established offshore production arenas. They can be used to provide historical context and act as points of reference. The concepts discussed are applicable to all offshore production regions.
Statoil's First Onshore Support Center: The Result of New Work Processes and Technology Developed to Exploit Real-Time Data
Authors: McCann Andrew , Omdal Svein , Nyberg Runar K.
Published: December 2007

Applying innovative technology and work processes to land support for offshore drilling and well operations enhances value creation chiefly through better well placement in the reservoir and more efficient operations. Over the last 5 years, new technological developments have driven an evolution in work practices towards greater integration between disciplines and over the large distances between offshore drilling operations and asset teams on land.

The Onshore Support Center (OSC) opened in December 2003 at Statoil's Mid-Norway operations office is a workplace where data and competency can meet, creating a perfect infrastructure for integrating operations. Integrated operations are a common industry goal, with widely recognized value. The center provides seamless data transfer & video-conferencing with rigs, platforms and vessels operating on Statoil's Halten/Nordland fields (via a fiber-optic cable/broadband radio), where onshore and offshore staff can share and co-visualize data and interpretations from drilling, completion and work-over operations.

The technical design of the center and the work practises used there, however, are based on a number of years of experience with increasing integration between offshore drilling operations and land-based support. To enable this evolution, a number of new technologies had to be developed, some of which have been commercialized or have led to new industry standards.

Multi-disciplinary collaboration is more natural and effective when both teams have the same data viewed at the same time in the same applications – this allows real-time data to be fully exploited. Making the drilled well data immediately available together with all offset well log and drilling data, seismic data, geological and petrophysical models opens opportunities for better drilling optimization, better controlled well correlation, near real-time formation evaluation, and therefore more optimal well placement for production. The ability of the land support team to quickly analyze the data for decision support is enhanced and reaction time to unexpected situations can be reduced.

This contribution details some of the technological developments which led to development of the Halten/Nordland OSC, showing how they have changed the way we work and affected the outcome of drilling operations.
Predictive Data Mining Techniques for Production Optimization
Authors: Zangl G. , Oberwinkler C. P.
Published: December 2007

This paper presents an approach, how predictive data mining models can be used to enhance and accelerate production of hydrocarbon reservoirs. The whole knowledge discovery process, combined with the automation of the data-flow bears significant potential for improving the current production practice. Predictive data mining models can perform different tasks. When they are applied automatically (i.e. scheduled after the acquisition of new data), they can reduce the workload of the knowledge workers significantly. These models act as gatekeeper, looking at the quality of data, as well as behavioral changes of wells or whole production systems.
Lessons Learned from Using Viscoelastic Surfactants in Well Stimulation
Authors: Nasr-El-Din Hisham A. , Tibbles Ray , Samuel Mathew
Published: December 2007

Viscoelastic surfactant systems are used in the industry for several applications. Initially, the application was focused on low friction and solids suspension (fracturing and CT- cleanout) characteristics of the fluid. In the last three years, the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. This is due to the ability of surfactant monomers to associate and form rod-shaped micellar structures under certain conditions.

Viscoelastic surfactant-based acid systems have been used in Saudi Arabian fields in matrix acid stimulation, and in leak- off control acids during acid fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical, long horizontal and multi-lateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. They were also utilized in gas wells to reduce acid leakoff, and create deep fractures in dolomitic carbonate reservoirs (250-275ºF). In addition, they were successfully employed to stimulate seawater injectors and disposal wells where the temperature was in the range of 100-120ºF.

More than 150 wells (oil, gas, water injectors and disposal wells) were treated with viscoelastic surfactant-based acid systems. The acid was placed either by bullheading, by using coiled tubing with or without a tractor. In some cases, these treatments included stages of emulsified or regular acids. All these wells responded positively to the treatment. There were no operational problems encountered during pumping these acids even when low permeability reservoirs were treated. Because these acid systems do not contain polymer, there was no need to flow back water injectors. However, the spent acid in oil and gas wells was lifted from the treated wells in a very short period of time. Finally, wells treated with surfactant-based acid systems showed sustained performance for longer times than wells treated with other acid systems.
The Value of Information: A Bayesian Real Option Approach
Authors: Galli Alain , Armstrong Margaret , G. Dias Marco Antonio
Published: December 2007

In this paper we propose a general methodology that applies Bayesian updating and real option theory to a probabilistic reservoir model, in order to assess the economic value of new information. The method has been tested on a gas field. The reservoir model that served as starting point for this study is described in companion paper1 at this conference. We studied four production scenarios that varied according to the size of the reserves, the city to which the gas was to be pumped and the planned level of the production plateau. Initially two wells and some seismic information were available. We show how to value the information coming from two new wells, and present guidelines for choosing between different exploitation scenarios in terms of their inherent risk.
Pressure Gradient Testing with a New Formation Pressure Testing During Drilling Tool
Authors: Meister Matthias , Pragt Jos , Buysch Arno , Witte Johannes , Due Gisle Nordahl , Hope Randi
Published: December 2007

Formation pore pressure is a key parameter for reservoir management in the Troll field. The pressure measurement traditionally performed on wireline is time consuming, especially in deviated wells. To provide the service earlier and more efficiently, a formation pressure tester has been developed as part of a Logging While Drilling bottom hole assembly. The tool measures pore pressures during brief pauses of the drilling process by extending a pad to the borehole wall, forming a seal against the formation, and performing a series of drawdowns.

To meet the challenges of short station duration and limited telemetry rates, the new tool is equipped with a downhole intelligent system for real-time operational decision. The flexibility of the design of the new tool allows basic pressure tests with preset draw down and buildup tests with preset fixed volume and rate, or repeated draw down and buildup tests with different drawdown rates and volumes optimized downhole in real-time.

The new LWD formation pressure testing tool (TesTrak) has been successfully applied in three deviated wells with inclinations between 50 and 90 degrees in the Troll field. In eight bit runs and 235 rotational hours, 231 pressure points at 89 stations have been performed over a drilling distance of 10,780 ft. Post-well analyses of the pressure data have further added confidence to the real-time data acquired during drilling. The objective in the first field test was to establish the pressure in a high and a low mobility sandstone section on both sides of an intersecting fault zone. In addition, reservoir connectivity between two compartments was proven with the real-time data. The objective of the second field test was to establish a fluid gradient in the well during a small TVD change in the horizontal section. The tool provided a real-time fluid gradient in the reservoir section over a 20 feet TVD drop over a 1000 ft long section. The pressure data were also used to optimize the mud program and drill the well efficiently. In the third field test three pressure gradients (one gas, and two water gradients) were established, which helped to determine reservoir depletion characteristics.

The tool performed well and subsequent analysis of memory data supported the real-time pressure measurements. The data obtained fit perfectly to the pre-drill model, which was based on wireline formation tester measurements in off- set wells. The successful operation of the LWD Formation Pressure Tester demonstrates a good potential for time/cost savings by replacing separate wireline- or pipe-conveyed formation pressure logging jobs. The pressure data could also be applied for optimizing the mud program and hence improve drilling efficiency.
Software Simulation and System Design of Dynamic Killing Technique
Authors: Blotto Paola , Tambini Mauro , Dellarole Edoardo , Bonuccelli Michele
Published: December 2007

Uncontrolled eruption of a well is one of the most critical accidents that can occur in the exploration and exploitation of hydrocarbon fields. Several well control methods have been developed to bring blowout wells under control as quickly as possible.

The dynamic killing technique is typically adopted when a relief well needs to control the event. The method calls for bringing the blowout well under control by pumping water (or brine) at a flowrate sufficient to exceed the formation pressure of the blowing well. This phenomenon occurs through a combination of kill fluid static head and frictional pressure losses of kill fluid in the blowout well.

Dynamic killing is constituted by a complex multi-phase fluid dynamic system with a complex geometry: blowing well, relief well and reservoir. An advanced model able to simulate the killing phenomenon during all its transients is necessary for applicability screening and system design.

A software has been developed under an HSE R&D project and implemented by an integrated work team made up of the safety, production, drilling and reservoir engineering departments of oil and service companies.

The dynamic killing software, by simulating the killing transient with a series of loops through submodels, correlates killing flowrate, breakthrough and killing time, relief bottom hole pressure and required killing pump head and power as outputs.

This model is able to simulate the dynamic killing of an atmospheric or underwater blowout event. It is also able to analyze the in-string killing disabling the reservoir submodel. This paper fully describes the dynamic killing model in terms of both subroutines (blowing well, relief well and reservoir models) and software applications (method applicability, system design, main killing parameters).

In addition, the results of software validation simulating dynamic killing cases in the field are reported. This analysis indicates good accuracy of the model in terms of transient duration and killing requirements.
Installation of the World's First All-Electric Intelligent Completion System in a Deepwater Well
Authors: Moreira Oswaldo M.
Published: December 2007

The world's first all-electric intelligent completion installation in a subsea deepwater well, carried out in August 2003, represented the culmination of five years of joint development, testing and onshore field trials by the operator, Petróleo Brasileiro S/A (Petrobras) and completion contractor, Baker Oil Tools. It also illustrates the extent to which new oilfield technologies, particularly those related to subsea/deepwater applications, have historically met with resistance for wide acceptance.

This paper describes the various phases of the five-year project by Petrobras and Baker Oil Tools to qualify the all-electric intelligent well system for deepwater applications. The paper also highlights lessons learned at each phase of the development project and describes how those lessons were applied in ensuing phases to improve the design and functionality of the intelligent completion system. Finally, the paper offers an explanation as to why acceptance for this type of system has been restrained as well as a prognosis for future system development and acceptance.
Aligning KM with Business Needs
Authors: Diz Agustín , Felder Benjamín , Girela Immaculada , Paredes Sergio
Published: December 2007

At Repsol a KM program is being implemented which considers 4 fundamentalaspects: a. Communities of Practice. b. Links to Training (what we know andwhat we don't know). c. Recognition. d. Quality Metrics.

In E&P, over 10 communities are in place, and working. These communitieshave enabled new ideas and processes for areas that go from training, businessprocesses, all the way to alignment with Business Strategy.

The issues we have tackled, problems encountered, and specific results willbe presented and discussed. Critical aspects, such as pitfalls encountered andfailures will be addressed as key learnings to be shared.

One example has been the increase in supply of workshops and courses(including mixtures of e-Learning with classroom work) for employees to attend, which needs to be properly controlled. Another is the work integrating specificbusiness processes with information systems for better decision making, whichcommunities have enabled simply by being able to draw on all the appropriatepersons from different Business Units.
Flow Profiling via Distributed Temperature Sensor (DTS) System - Expectation and Reality
Authors: Ouyang Liang-Biao , Belanger Dave
Published: December 2007

Permanent downhole monitoring can provide valuable information for production decisions in real time without the need to perform an intervention to collect data. One of the commercial permanent monitoring technologies is fiber-optic distributed temperature sensor (DTS) which can record the wellbore temperature profile in real time with decent accuracy and resolution. A key potential application for DTS data is to profile injection or production for wells, which is the primary motivation and focus for this project.

In the present paper a thermal model recently developed for single phase and multiphase fluid flow along a vertical, deviated or horizontal well will first be briefly described. The model can be applied for both wellbore temperature prediction (forward modeling) and flow profiling using a measured temperature profile (inverse problem).

The model has successfully been applied for investigating key thermal characteristics of single phase and multiphase fluid flow along a wellbore. In particular, the dependence of wellbore temperature upon phases, flow profile, fluid type, fluid properties, well deviation, and Joule-Thomson effect, will be demonstrated in the paper. The model has further been adapted for directly predicting production and injection profiles (i.e., flow profiling) based on given wellbore temperature profile. The potential impact of noise in the DTS measurement on flow profiling has been explored.

It is found that the wellbore temperature does not change significantly along horizontal or near horizontal sections due to the small variation in geothermal temperature, therefore, just based on DTS data, the amount and the location of each fluid entry would be difficult to be identified. The current study shows that a maximum wellbore deviation of 75 degrees should be honored to appropriately estimate flow profile directly through DTS data. The study has also led to an observation that under certain circumstances like multiphase flow, a production profile may be determined via DTS temperature measurement with extra data or information provided. The types of the extra measurements and the appropriate approaches will be recommended.
Petroleum Engineering Education - Challenges and Changes for the Next 20 Years
Authors: Cunha J. C. , Cunha Luciane B.
Published: December 2007

This article indicates some basic knowledge and skills that should be present on the education of today's petroleum engineering students. Concurrently it presents some thoughts and points out directions for petroleum engineering education in the next few decades.

The importance of interaction between petroleum engineering schools and the oil industry is analyzed and some directions to improvement of this relationship are given.

The challenge and importance of attracting better and brightest students are commented and some suggestions related to how schools and industry should jointly participate in the efforts to keenly achieve this goal are listed.
The Importance of Rigorous Asset Analysis as Input to Portfolio Optimization: Practical Lessons from Recent Experience
Authors: Simpson G. S. , Ross J. G. , Ghazi T. Y.
Published: December 2007

There is a growing suite of innovative new portfolio analysis tools available, but there are still many questions about how to turn the theories, tools and techniques into tangible profit improvements. One thing is clear, however. The results of portfolio optimization strongly depend on the quality of the standalone asset analyses that are used as input.

This paper illustrates ways of avoiding pitfalls and improving the rigor of standalone asset analyses. It also sets out methods for understanding, implementing and deriving the best value from the latest project optimization techniques.

Specifically, the paper illustrates the importance of: Understanding the interaction between standalone asset analyses, portfolio optimization and portfolio management strategy formulationApplying a structured framework for analyzing, planning and managing the development of projectsUsing a new synergistic approach to the evaluation of critical assets that compresses decision cycles and enables a large technical-to-business team to discover potential step-changes in project profitability and more rigorously assess uncertaintyFinding a common language between the different functions involved in portfolio management, facilitating communication and constant, dynamic innovation in proceduresBuilding a corporate culture that understands risk and uncertainty, knows how to deal with them, and actively encourages advances in asset analysis and portfolio management practices

The combination of these techniques allows a much closer approximation to the "full, risked, probabilistic values"1 of individual assets that are required as inputs to portfolio optimization analysis. Thus, the full power of portfolio optimization can be realized, through identifying the most profitable combination of projects, making optimal use of resources and thereby driving up a company's profits.
Thunder Horse Drilling Riser Break – The Road to Recovery
Authors: Kirton Bill , Wulf Gary , Henderson Bill
Published: December 2007

This article presents key learnings by BP's Wells Team on the Thunder Horse project after responding to a major incident— the break of the drilling riser on the Discoverer Enterprise drillship in May 2003 in the Gulf of Mexico. Even though BP has established policies for the immediate incident response phase and conducts training exercises, there is less focus on the later recovery phase. This paper increases the awareness of critical project management issues that may arise during transition from the response to recovery phase after a major incident.
Design of Intelligent Well Downhole Valves for Adjustable Flow Control
Authors: Konopczynski Michael , Ajayi Arashi
Published: December 2007

This paper describes the considerations and integrated design process for specifying the Cv characteristics of an adjustable flow control valve for an intelligent well. The paper emphasizes the need to consider the complete well as a control system, including inflow, choke performance and well bore outflow performance.

The paper describes a method for establishing the most suitable flow control design for the application. The method combines nodal analysis and choke performance modelling to model the behaviour of the entire well bore system. This analysis is extended to multiple layer or multiple zone intelligent well completions. An example of the analysis is presented.
Dilution Strategies for Wax Management and Control for Deepwater Development from a Flow Assurance Perspective: Part I – Current Practice and Perspective
Authors: Singh Aditya , Benavides María S. , Saint Marcoux Jean-Francois , Barrufet María A.
Published: December 2007

Oils with high wax content may cause pipeline plugging and deterioration of equipment, resulting in production shutdowns and economic losses. At present, various mechanical, thermal and chemical methods are used for wax management, however these methods can cause additional problems and can be very expensive. Dilution can be used as an alternative or can be combined with current wax-management methods. This paper identifies dilution strategies for a range of waxy crudes from different oil producing regions of the world.

Prevention and control of wax deposits by blending heavy fractions of oil with lighter fractions is achieved with tools currently available in the industry. Mixing rules and blending correlations to suppress the wax appearance temperature (WAT) can be developed. A database of fluids with a range of wax contents from different regions of the world was created and used in this analysis. A way forward in modeling, control, and remediation is proposed, and possible areas of further research and development are identified.

Expensive thermal and chemical solutions are currently required to produce fluids with high wax content in deep-and ultra deep-water field developments.

The results are promising. Unique flow-assurance solutions can be achieved by addition of diluent. Injecting 6 to 23 MSCF Lift gas/1000 bbl crude in low GOR fluids can achieve a WAT reduction of 6 to 7°F. Other diluents evaluated demonstrated that with ratios of 0.5 – 4 bbls of diluent/1000 bbls of crude, a WAT reduction of 6-13°F could be achieved.
Improved Horizontal Well Stimulations in the Bakken Formation, Williston Basin, Montana
Authors: Wiley Charles , Barree Bob , Eberhard Mike , Lantz Tom
Published: December 2007

The Bakken formation in the Williston Basin of Montana has undergone rejuvenation thanks to the success of horizontal drilling and completions. Over the last several years there has been an evolution in the drilling and completion methodology, which has resulted in significant improvements in well productivity. Although the horizontal wells will produce at economic rates without stimulation, hydraulic fracturing increases well productivity significantly. For the program discussed in this paper, the wells are drilled for longitudinal fracture orientation. The original wellbores had cemented liners and employed the limited-entry technique to distribute the fracture treatment. This program now uses noncemented liners and a modified fracture treatment with diverter stages.

This paper presents a review of the approach taken to evaluate the most effective way to complete and hydraulically fracture these laterals. It documents the evolution of the hydraulic fracture design and wellbore configurations. It also presents results showing the improvements in proppant distribution along the wellbore caused by changes in fracture treatment design and its impact on well productivity.