bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling Fluid Losses and Gains: Case Histories and Practical Solutions
Authors: Tare Uday A. , Whitfill Donald L. , Mody Fersheed K.
Published: December 2007

Identification and resolution of drilling fluid losses and gains while drilling have gained in importance due to the high cost of deepwater drilling focusing concern on any delays. Drilling fluid losses and gains, or wellbore breathing, can be attributed to several factors. These include the local geological setting, inherent natural fractures in the formation, well trajectory, drilling operations, equivalent mud weight, mud rheology and chemistry, etc. Recurring observations of formation influx while drilling or during connections oftentimes are interpreted as a potential well control situation. Therefore significant rig time can be lost to insure this is not the case. There have been recent developments in the area of monitoring drilling fluid losses and gains. A fundamental understanding of the reasons for mud losses and gains, along with the implementation of these recent monitoring techniques, would greatly improve managing this problem.

In this work, mechanisms are provided to explain drilling fluid losses and gains. Loss and gain situations can occur in a variety of drilling scenarios: examples would be while drilling in deeper waters, where the operating window between the pore pressure and fracture gradient is narrow; drilling extended reach wells where the problem may be encountered at higher hole inclination angles; drilling though formations with abnormally high geothermal gradients, etc. In addition, case histories are provided where drilling fluid losses and gains were diagnosed during a borehole stability analysis, followed by implementation of recommended remedial measures that resulted in better management of the problem on later wells. Sometimes potential for mud losses and gains are interpreted from formation leak-off tests. New solutions, which include alterations to the drilling fluid composition and lost circulation sweeps, are proposed to help mitigate the occurrence of drilling fluid losses and gains.
Successful Well Control in the Cantarell Field Applying the Dynamic Method
Authors: Carlos Osornio V. , Humberto Castro Mtz. , Victor Vallejo A. , Enrique Ayala V.
Published: December 2007

While drilling the gas cap zone of the offshore Cantarell 69-I well, a gas kick was taken, becoming a blowout. The gas ignited, causing a large fire situation, and as a consequence the drilling rig was severely damaged.

Due to the flowing conditions of the well, it was not possible to achieve well control through the tubing string. Therefore, two different alternatives were analyzed to solve the problem: momentum and dynamic kill. This paper presents the results obtained applying both techniques, as well as the well control analysis and procedure.

First, the pressure profile in the well was calculated, as well as the gas flow rate (230 MMscfd) in blowout conditions. Then the kill flow rate (considering seawater) was calculated for both methods. The dynamic method yielded a kill flow rate of 19 bbl/min. Once the flow rate required to control the well was defined, the casing head was inspected to assure the success of the attempt, and it was in good condition to perform the operations.

The operative sequence to control the contingency in a minimum time consisted of connecting the 20 x 13 3/8-inch casing head to a cementing ship through 2-inch lines in order to pump seawater. The total time required to control the gas blowout was 11 hours after the kick was taken. The success consisted of reaching a flowing pressure at the tie-back depth (680 m) greater than the reservoir pressure, which was generated by the frictional pressure losses and the hydrostatic head of the multiphase flow (gas and seawater) inside the injection string.
Real-Time Measurement of Downhole Annular Cementing Temperature for Precise Cementing Design and Application
Authors: Dillenbeck R. L. , Mombourquette I. G.
Published: December 2007

The tests required to customize a cement system for a well are run either at Bottom Hole Static Temperature (BHST) or at a lesser temperature known as Bottom Hole Circulating Temperature (BHCT), depending on the specific test being run. Many of the characteristics being optimized in a cement system must be tested as closely as possible to the actual temperature encountered by the cement slurry as it is circulated into a well. Failure to test the system at the correct temperature can result in improper loading of expensive additives, and expensive cementing failures. Many in the industry have long realized that standardized API tables will not always give the most accurate representation of BHCT for every well. In order to most accurately design a cement system, it is necessary to have a better understanding of the actual temperature encountered by the system during placement in a given well. Accordingly, computer models have been developed to simulate conditions encountered down hole. Having worked with such programs, the authors believe that in order to be accurate, most of these models require lithological thermal conductivity, and fluid specific heat data that is not generally available on most new wells. Because of these requirements, many simulations are run where "default" or "average" input values are used, and the Circulating Temperature projections become highly educated guesses.

In an effort to procure more accurate and useful data, technology has been developed that allows for the monitoring of annular temperature of all fluids during placement of cement in a new well. Further, the technology allows for continued monitoring of the cement temperature during the critical cement transitory hydration phase, as well as throughout the life of the well. The authors will detail the development of the technology and the actual application in the field in multiple countries. Data obtained from wells utilizing the technology is analyzed and compared to current API values as well as BHCT projections from a Finite Analysis computer model. Finally, the authors will detail how the information made available by this technology can be applied to provide more accurate, fit for purpose cement designs that are optimized for the actual conditions encountered in a well.
Innovative Solution for Cementing Across Formations with Very Low Fracture Gradients
Authors: Hun Christian , El-Hassan Hassan , Husam Helou , Hasni A. Latif , Mohsen A. Hameed
Published: December 2007

Lost circulation is a common problem in the massive Simsima and Umm El Radhuma carbonate formations that extend across all United Arab Emirates fields and the Gulf countries. To minimize losses during drilling, 8.10-lbm/gal emulsion mud or aerated mud is often used.

As the result of corrosive brines presence across the formations extending to the shallow depths and causing casing corrosion problems, one of the main objectives of cementing the 9 5/8-in. casing is to ensure well integrity and casing protection by having cement to surface.

In these carbonates, multistage cementing tools have operational problems and frequently develop casing leaks over the life of a well. Top jobs do not guarantee complete linear and radial coverage of the casing along the whole interval. Complete losses are expected with conventional lightweight cement systems, and their set cement properties do not meet requirements for casing corrosion protection. These issues make successful cementing in these formations a real challenge.

To overcome the challenges, a new ultralightweight cement system (ULC) with a density close to that of water and superior set cement properties was used to ensure good casing protection and zonal isolation. This paper addresses the challenge to measure the low density of the slurry and the tools necessary to differentiate between mix fluid and the final slurry.

The new ultra-lightweight cement was evaluated using standard cement evaluation logs, and case studies are presented that confirm successful zonal isolation.
Real Options and Probabilistic Economics: Bridging the Gap
Authors: Hooper H. T. , Rutherford S. R.
Published: December 2007

Three approaches to economic evaluations that have been widely discussed in the literature are decision trees, Monte Carlo simulation, and real options. Authors have shown that the incorporation of decision tree logic into Monte Carlo simulation offers an added degree of insight into the evaluation, and generally provides a more realistic valuation of an asset by incorporating some degree of management decision making. While probabilistic economics (either decision trees or Monte Carlo simulations) and real options differ significantly in the type and amount of input data, as well as the format and applicability of output, they both have capability to capture some value of active decision making by management. This paper attempts to bridge the gap between the two approaches, at least conceptually, for the practicing engineer. Rather than take an academic approach, the authors illustrate key points through real world examples. Also, since discount factors are often considered the most fundamental difference between the discounted cash flow and options pricing approaches, the implications of that issue are discussed as well. Finally, attempts to "compensate" option-pricing algorithms such as the classic Black and Scholes are discussed, in an effort to incorporate more reality into real options evaluations.
Project Profitability and the Economics of Sustainable Development
Authors: Agbon I. S.
Published: December 2007

In the past economic models captured economic externalities such as sustainable economic development as additional investments that increased project operational costs. There is a need to internalize investment in sustainable economic development in project profitability models. This paper develops a model that captures economic returns from oil and gas investments from the different perspectives of the four major stakeholders in oil and gas operations. These four major stakeholders are the oil companies, the shareholders, the society and the host communities. The cost of sustainable economic development has different impacts on the financial conditions of each of the stakeholders. Each stakeholder therefore has its unique economic perspective defined by its minimum rate of return and its view of project profitability.

The perspective of the oil companies use the cost of borrowing capital as its absolute minimum rate of return while that of the shareholder uses the bank saving rate of return. The absolute minimum rate of return for the society captures the replacement of oil and gas as wasting assets, while that for the host communities encompass the replacement of the income generating capacity lost due to environmental pollution as well as the cost of maintaining the economic regenerative capacity of the environment. The project must be profitable from the unique point of view of each of the major stakeholders for sustainable economic development to occur. Project profitability from the perspective of the host community is the sustainable economic development test.

The paper concludes that oil and gas ventures can be screened with the four perspectives profitability model to ensure that they will enhance sustainable economic development understood from the perspective of each of the major stakeholders. Screened investment opportunities that are profitable from the four perspectives can then be ranked on the basis of profitability from the perspective of the oil companies.
Produced Water: Environmental Issues/ Technological Solution of the Nigeria Depletion Era
Authors: Ukpohor T. O.
Published: December 2007

Environmental literatures have been greatly concerned with possible detrimental effect of continued produced water discharged in offshore and onshore areas. While it remains a major policy for the operating companies in Oil production to be environmental friendly in achieving their goal of maximum petroleum exploitation, certain natural phenomenon tends to pull a negative effect on the production of Produced water as an inevitable associate of crude oil.

As the Depletion of crude oil reservoirs in Nigeria becomes more evident by nature of maturing field, the production of Produced water, which varies directly as Depletion will be increasing at almost a geometric rate that effective treatment of this effluent may elude the various Operating companies. With a case study of field F in the Niger Delta, this paper technically reviewed the environmental issues of the pollution effect of Produced Water, inductively analyzed the Depletion Rate of the case study and recommended technological solution to this problem.

Illustratively, a schematic flow diagram relating the technological solution was made, delineating the various option of Produced water Disposal Systems that are within expectable standards, conforming to flora and fauna safety.
e_Business and Asset Teams: A Perspective
Authors: Woolley Thomas C. , Wittstrom Martin D. , Wright Brian J.
Published: December 2007

E-Business initiatives are common today in medium and large size oil companies, and new ones continue to develop as companies identify and review opportunities to use Internet technology to improve their operations and productivity. Opportunities for sustained efficiency gains through the use of electronic commerce and communication solutions offer benefits for all portions of the petroleum value chain. The technical and business problems are often similar and therefore offer leveraging opportunities to port technology and solutions across different sectors of the value chain. The impact on petroleum industry professionals continues to increase as capabilities in the different business sectors continue to grow. Asset Teams, whether they are in the upstream, midstream, or downstream sectors are likely to be active participants in one or more type of business space: Business-to-Consumer (B2C) commerce (e.g. purchasing of data, materials and services); Business-to-Government (B2G) activities (e.g. permitting and acquisition of lease information from government agencies), and Business-to-Business (B2B) commerce (e.g. direct linking of suppliers and business partners to receive products and services to directly link work processes such as AFE approvals).

This paper will discuss some experiences and observations of asset teams relating to e-Business solutions. Examples of these would include improvements in teamwork, productivity, joint venture communication, management information reporting, property acquisition and divestment, and virtual workgroups. Barriers to success, lessons learned and future development predictions will be described.
Methane Hydrates: Major Energy Source for the Future or Wishful Thinking?
Authors: Thomas C. P.
Published: December 2007

Methane hydrates are methane bearing, ice-like materials that occur in abundance in permafrost areas such as on the North Slope of Alaska and Canada and as well as in offshore continental margin environments throughout the world including the Gulf of Mexico and the East and West Coasts of the United States. Methane hydrate accumulations in the United States are currently estimated to be about 200,000 Tcf, which is enormous when compared to the conventional recoverable resource estimate of 2300 Tcf. On a worldwide basis, the estimate is 700,000 Tcf or about two times the total carbon in coal, oil and conventional gas in the world. The enormous size of this resource, if producible to any degree, has significant implications for U.S. and worldwide clean energy supplies and global environmental issues.

Historically the petroleum industry's interests in methane hydrates have primarily been related to safety issues such as wellbore stability while drilling, seafloor stability, platform subsidence, and pipeline plugging. Many questions remain to be answered to determine if any of this potential energy resource is technically and economically viable to produce. Major technical hurdles include: 1) methods to find, characterize, and evaluate the resource; 2) technology to safely and economically produce natural gas from methane hydrate deposits; and 3) safety and seafloor stability issues related to drilling through gas hydrate accumulations to produce conventional oil and gas. The petroleum engineering profession currently deals with gas hydrates in drilling and production operations and will be key to solving the technical and economic problems that must be overcome for methane hydrates to be part of the future energy mix in the world.
Novel Low Dosage Hydrate Inhibitors for Deepwater Operations
Authors: Fu B. , Neff S. , Mat hur A. , Bakeev K.
Published: December 2007

Novel low dosage hydrate inhibitors (LDHI) have been developed for applications in oil and gas fields. The new-generation inhibitors work as kinetic inhibitors that prevent hydrate formation encountered frequently in deepwater operations. These chemicals effectively inhibit hydrate formation regardless of the water cut in the system. They also exhibit a low toxicity that leads to very favorable environmental ratings. Valuable experience has been learned from recent laboratory studies as well as field trials with respect to the application limits and implementation techniques for these new products. The key to the overall success is a full integration of a good front-end design, a comprehensive deployment plan and an effective monitoring program. An overview of the chemistry of these new inhibitors along with their performance under simulated deepwater conditions is briefly discussed. In addition, the effect of LDHI on hydrate formation and the effect of pressure on LDHI performance are addressed.
Development of a Foam Monitor for High Pressure Separators
Authors: Poindexter M. K. , Marsh S. C. , Fransen G.
Published: December 2007

Many deepwater platforms installed in the Gulf of Mexico produce large amounts of both gas and oil. Due to the limited space aboard these vessels, some separation equipment may become undersized particularly when record setting production rates are attempted. Additionally, there is increased activity in adding new subsea production to platforms that are within specified production limits. When the increased throughput arrives, separation equipment can be overloaded. In other instances, the addition of a new well (or wells) to existing production can greatly change the foaming characteristics of the overall composite. If the change is towards more severe foaming, an immediate problem can arise.

The high pressure separator (HPS) is where gas/oil separation begins. It is imperative that efficient separation occurs in the HPS, otherwise performance in downstream vessels will likewise diminish. With enough foaming, the platform can be forced to take an unwanted, and sometimes unexpected, shutdown.

Foaming can often be viewed as a two-fold problem. While foam (or liquid carry-over) takes place through the overhead outlet of the HPS, there is generally simultaneous gas carry-under through the bottom outlet of the separator. This "double problem" can often be observed by watching process gauges (e.g. pressure, flow rate, and level monitors). While these monitors are often useful for detecting foam, they are located either after the HPS or often do not respond quickly to an impending foam situation. To develop an immediate response to separator foaming, a probe was developed to monitor the conditions directly within the HPS. Lab development and field evaluation of a probe capable of handling the high pressure and flow rates of a HPS will be reviewed. Examples of using the probe to assist in selection and optimization of antifoams will also be presented.
New Coreflood Interpretation Method for Relative Permeabilities Based on Direct Processing of In-Situ Saturation Data
Authors: Goodfield M. , Goodyear S. G. , Townsley P. H.
Published: December 2007

Generation of good quality relative permeability data depends on carefully designed core flooding programmes, combined with appropriate interpretation of the laboratory data. Where capillary pressure is important simulation based methods are needed. However, experience shows that the conventional fixed capillary pressure outlet boundary condition may fail to capture the development of the in-situ saturation profiles satisfactorily.

This paper describes a new interpretation approach that fully utilises in-situ saturation data and reduces the sensitivity to boundary condition assumptions. The method extends previously published techniques for interpreting gravity drainage floods by including viscous and capillary forces. Relative permeabilities are calculated directly from in-situ saturation and pressure drop data, without the need to use simulation methods, by applying the Darcy flow equations for the mobile phases at each position and time in the core. Darcy's equations are recast to give separate pressure and fractional flow equations. The fractional flow equation is solved locally, independently of any boundary condition assumptions, and the pressure equation (written in a global integral form) is solved for the mobility. The algorithm is applicable to a wide range of water-oil displacements or gasoil displacements with an immobile initial water saturation, including multi-rate and constant pressure drop unsteady-state floods, steady-state and gravity drainage floods.

The algorithm is applied to synthetic saturation and pressure drop data sets generated using a conventional simulator for a selection of water/oil and gas/oil core floods. The underlying relative permeabilties are correctly constructed, including a significant fraction of the oil relative permeability tail. A range of smoothing methods have been developed to allow the basic algorithm to be successfully applied to datasets in which noise has been added to the basic saturation and pressure profiles generated by simulation.
Physical Effects of WAG Fluids on Carbonate Core Plugs
Authors: Svec R. K. , Grigg R. B.
Published: December 2007

It is a given that carbonate mineral dissolution and deposition occur in a formation in geologic time and are expected to some degree in carbon dioxide (CO2) floods. Water-alternating-gas (WAG) core flood experiments conducted on limestone and dolomite core plugs confirm that these processes can occur over relatively short time periods (hours to days) and in close proximity to each other.
Effect of GOR, Temperature, and Initial Water Saturation on Solution-Gas Drive in Heavy-OIl Reservoirs
Authors: Tang G. , Firoozabadi A.
Published: December 2007

We have carried out an extensive set of tests on solution-gas drive for a heavy oil to study the effects of initial water saturation, temperature, and gas-oil-ratio (GOR). The viscosity and the API gravity of the stock tank oil from Hamaca field (in Venezulela) used in our tests are 560,000 cp (at 24°C) and 8.7, respectively. The solution-gas drive tests were conducted using live oils with GOR of 6.5, 9.0, and 12.2 (vol/vol at standard conditions). In two tests, initial water saturations of 4.0 and 5.2% were established. Five tests were conducted at a temperature of 35°C; one test was conducted at 46°C. The duration for each test was around three months. Based on the results from all the tests the following conclusions can be drawn. Initial water saturation reduces gas-bubble density. The recovery efficiency decreases due to increase in gas mobility with increase in initial water saturation. As the temperature increases from 35 to 46°C, the gas relative permeability increases one order of magnitude; as a result there is reduction in recovery efficiency. The temperature effect on recovery is in agreement with our previous work with temperature increase from 24 to 35°C. Increase in solution GOR has a significant effect on gas-bubble nucleation; there is a systematic increase of the critical gas saturation with GOR increase. For all the tests conducted, the oil recovery by solution gas drive at test termination was about 16 percent and higher.
Experimental and Theoretical Assessment of Using Propane to Remediate Liquid Buildup in Condensate Reservoirs
Authors: Jamaluddin A. K. M. , Ye S. , Thomas J. , D'Cruz D. , Nighswander J.
Published: December 2007

This paper presents the results of an assessment of condensate phase behavior issues in the near-wellbore region. Constant composition expansion (CCE) studies were conducted to measure the retrograde liquid deposit data for a real reservoir fluid. Subsequently, the effect of adding light hydrocarbon gases on the vaporization of condensed liquid was studied. An equation of state (EOS) model was developed based on the measured data and was used to evaluate the experimentally observed phase behavior characteristics of the condensate fluid. Results indicate that although carbon dioxide can influence the liquid extraction properties of the condensate wellstream to some extent, the use of propane allows the system conditions to be supercritical conditions for most typical reservoir fluids at reservoir temperature and pressure. This allows for an enhanced liquid extraction capability, which subsequently improves wellbore extraction.
An Integrated Electric Flow-control System Installed in the F-22 Wytch Farm Well
Authors: Tourillon V. , Randall E. R. , Kennedy B.
Published: December 2007

The increased complexity of hydraulic and complex electrohydraulic flow-control systems, especially with multizone completions, substantially increases deployment risk. Until now it has not been possible to provide an infinitely variable flow-control system for multiple zones using only a single conduit from surface.

The BP Wytch Farm F-22 well has an all-electric tubing-retrievable flow-control device installed as the primary active downhole component in the intelligent completion system. This device integrates an electromechanical adjustable choke, multiple quartz pressure and/or temperature sensors, and a mass-flow sensor, all powered from the surface through one permanent downhole cable. Multiple flow-control devices can be run on the same cable to provide zonal control and monitoring. Each device is independently addressable, allowing the operator to adjust any zone in the well on command and react to potential reservoir uncertainties in real time. The presence of an electric pump cable near the permanent downhole cable at the Wytch Farm installation has demonstrated that the communication system working on a twisted pair cable is immune to noise.

The fully electrical system can establish a secure link between multiple downhole sensing and flow-control components, the surface acquisition system, and remote control locations where reservoir engineers and production specialists can monitor and control well operations. Infinitely variable flow control coupled with real-time monitoring and data transmission will facilitate and accelerate the development of subsea, deepwater, and other hostile location wells by eliminating the need for surface or close infrastructure.
Kinetic of Hydrates Formation: Influence of Crude Oils
Authors: Sinquin A. , Bredzinsky X. , Beunat V.
Published: December 2007

As deepwater offshore production is widely developing, the problem of flow assurance becomes of major importance. Among the problems that can be encountered, flow lines plugging by hydrates is particularly dread. The kinetic of hydrate's formation is greatly influenced by the nature of the crude oil produced and the management of hydrate's problems could be quite different from one field to another.

We have studied the kinetic of hydrate's formation using four different liquid hydrocarbon phases: a condensate, a paraffinic and two asphaltenic crude oils. The kinetic of hydrate's formation has been studied in a semi-batch stirred reactor. Experiments have been carried out in presence of these liquid hydrocarbon phases, at a constant pressure by decreasing temperature. The induction time, the quantity of hydrates formed and their rate of formation have been determined at different water cuts.

Two types of kinetic behavior have been found: the condensate and the paraffinic crude show very violent and rapid hydrate's formation, while hydrate's formation with the asphaltenic oils is delayed and the crystallization is very smooth.

The influence of the liquid hydrocarbon's composition (paraffin content, WAT, asphaltene's solubility…) has been explored. The effects of the water cut and of liquid hydrocarbon's viscosity have been also studied. Among these, the most relevant parameters having an important effect on the kinetic of hydrate's formation have been pointed out.

This work highlighted the importance of the nature of the liquid hydrocarbon phase on the kinetic of hydrate's formation. Specific studies on the influence of the hydrocarbon phase can give precious information for hydrate's management problems in deepwater offshore development.
A Tale of Two Trees: Flow Assurance Challenges for Wet Tree and Dry Tree Systems in Ultradeepwater
Authors: Golczynski T. S. , Niesen V. G.
Published: December 2007

As oil and gas exploration moves into deeper waters offshore, flow assurance challenges become more prevalent and system design must address these issues from a fresh perspective. In addition to structural and economic issues, the decision to employ either a wet tree (subsea) or dry tree solution needs to especially consider the flow assurance aspects that ultradeepwater production presents. The riser, rather than the flowline, will now dominate the overall hydraulic and thermodynamic performance of the system. An increased liquid column height in the riser, a greater potential energy change, and an enhanced Joule-Thomson effect will all contribute to significant temperature and pressure drops for an ultradeepwater riser, relative to its shallow water counterpart.

Dry trees are traditionally perceived as having less severe flow assurance issues than subsea tiebacks, primarily because of easier access to the tubing string if wax or hydrates are formed. However, aside from significant temperature losses in the riser, dry trees in ultradeepwater are particularly susceptible to hydrate formation upon shutdown. Because of warmer seabed temperatures and lower reservoir pressures, shallow water dry tree risers can provide adequate cooldown times with only minimal insulation. For ultradeepwater developments, the same shallow water dry tree design can fall into the hydrate formation region within two to three hours.

For both the dry tree and wet tree riser systems, it may not be possible to depressurize the system below hydrate formation conditions without gas lift (which may not be available for an emergency shutdown). The focus of this discussion is to evaluate the merits and drawbacks for both wet and dry tree systems from a flow assurance standpoint in ultradeepwater.
A Systematic Approach in Deepwater Flow Assurance Fluid Characterization
Authors: Jamaluddin A. K. M. , Nighswander J. , Joshi N.
Published: December 2007

The potential for hydrocarbon solid formation and deposition adversely affecting flow assurance in deepwater production systems is a key risk factor in assessing deepwater developments. To reduce this risk, a systematic approach to defining and understanding the thermodynamic and hydrodynamic factors impacting flow assurance is required. The development of experimental and simulation techniques to provide this information are a current focus of attention in the reservoir fluid phase behavior community. This paper provides a case study of the various aspects of a state of the art laboratory and simulation assessment for a Gulf of Mexico reservoir crude. The case study illustrates the application of a systematic approach to characterization of the crude and the impact of this knowledge on potential production and flow assurance strategies.
Novel Inlet Design Expense Range of Operability for Compact Separator
Authors: Barbuceanu Nicolae , Scott Stuart
Published: December 2007

The concept of compact separation is attractive in a number of operating environments. These include offshore and arctic operations where both space and weight are at a premium and subsea and downhole processing where space is very limited. Compact separators often rely on centrifugal forces to enhance the separation process and are therefore highly dependent on inlet geometry. This paper investigates expanding the operational envelope of a compact Gas Liquid Cylindrical Cyclone separator through the use of a novel inlet, which can be easily altered to respond to changing well conditions. To demonstrate the importance of inlet geometry, historical production from the Gloyd-Mitchell zone of the Rodessa Field in Louisiana was examined over a 40-month period. As in most oil field production, there were significant changes in the water cut and GOR. This field data clearly shows that a compact separator equipped with single inlet geometry is not able to perform effectively over the wide range of conditions exhibited in a typical oil field. This paper models the hydrodynamics in the separator inlet. Three different inlet geometries were investigated through the use of a changeable inlet sleeve. New experimental data were acquired utilizing a 7.62-cm I.D compact separator, which was 3.0 m in height. The effect of inlet geometry on separator performance was investigated over a wide range of flow conditions. Fluid viscosities from 1-12 cp and the effect of fluid level within the separator were also examined. The results indicate that the operational envelope for liquid carry-over and gas carry-under can be expanded by more that 300% by altering the inlet to respond to changing field conditions.
Life Cycle Management of Scale Control within Subsea Fields and its Impact on Flow Assurance, Gulf of Mexico and the North Sea Basin
Authors: Jordan M. M. , Sjuraether K. , Collins I. R. , Feasey N. D. , Emmons D.
Published: December 2007

This paper presents an overview of life cycle flow assurance management for a platform/subsea development by focusing on scale control. To illustrate this approach examples of scale control methods for deepwater subsea fields will be cited covering aspects such as (1) treatment of the reservoir prior to production to prevent scale formation within the near wellbore (solids and fluid system for inhibitor deployment), (2) downhole scale control using continuous injection (gas lift, capillary), and (3) squeeze treatments as the production wells move through their life cycle and water cut rises. The management of scale and corrosion issues within a subsea field will be reviewed with examples of an operator moving from combined scale inhibitor/corrosion inhibitor products to single corrosion inhibitor product at the manifold as water cut rise. The scale control within this field was achieved with squeeze treatment residuals protecting the reservoir through the topside process without the need for additional scale inhibitor injection. A review will be presented on how this field could have been developed if all today's scale control/monitoring technology had been available during the CAPEX phase of field development and how this might have an impact on field economics.

The paper will outline the methods used to assess the risk of scale and the associated risk manageability of the problem and review how this risk changes through the life cycle of subsea assists under seawater drive and natural depletion. The process and methods of assessing the risk of scale formation during produced water injection will also be addressed.

The scale control technology developments have been driven by these perceived risks. Many of the technologies have already been tested within the North Sea. Furthermore, there are trials planned in the deep water fields of the Gulf of Mexico and West Africa.
An Approach to Mitigating Wellbore Solids Deposition
Authors: Kabir C. S. , Hasan A. R. , Lin D. , Wang X.
Published: December 2007

Tubular flow restrictions owing to solids deposition are serious oilfield problems. Solids normally originate from either asphaltic or paraffinic oil. Hydrates add another dimension to the problem when water production begins. Most solutions center on the use of aromatic solvents for asphaltenes and chemicals or heating for paraffins.

In this study, we seek preventive measures to minimize solids deposition by altering characteristics of fluid flow in the wellbore. Knowledge of thermodynamic behavior of fluids and application of principles of fluid and heat flows constitute the essence of our approach. Specifically, we present a steady-state model that allows computation of wellbore pressure and temperature profiles for a hot-circulating fluid in case of parrafins. The same model is used to study the p-T behavior of asphaltic oil while circulating a cold fluid.

A fluid-temperature model is also presented when intermittent or continuous injection of solvent is sought through a chemical-injection line. Both models are general in that flows in offshore wells can be handled rigorously.

Computational results show that preserving energy of paraffinic oil is feasible by circulating hot fluid in the annulus and/or using insulation, thereby keeping solids in solution. The use of an unsteady-state flow model sheds light on the time available for well intervention before the onset of deposition. Similarly, cooling of fluids may help produce asphaltic oils under favorable conditions.
Automated Reservoir Model Selection in Well Test Interpretation
Authors: Güyagüler Baris , Horne Roland N. , Tauzin Eric
Published: December 2007

Technological achievements in the area of well testing, such as permanent downhole gauges, demand automated techniques to cope with the large amounts of data acquired. In such an application, the need to interpret large quantities of data with little human intervention suggests the desirability of automated model recognition. Also in some cases the characteristic behavior of the pressure or its derivative curves for specific models may be hidden behind noise or human bias may lead to the selection of an invalid or inappropriate model.

This paper demonstrates an approach based on Genetic Algorithm (GA) that is able to select the most probable reservoir model among a set of candidate models, consistent with a given set of pressure transient data. The type of reservoir model to be used is defined as a variable and is estimated together with the other unknown model parameters (permeability, skin, etc.). Several reservoir models are used simultaneously in the regression process. GA populations consist of individuals that represent parameters for different models. As the GA iterates, individuals that belong to the most likely reservoir model dominate the population, while less likely models become extinct. Since different models may require different numbers of parameters, the solution vectors have varying lengths. The GA is able to cope with such solution vectors of differing size. Information exchange (GA crossover operator) is allowed only between parameters that are physically related.

Alternatively, we illustrate the use of GA as a preprocessor for conventional gradient-based algorithms such as LevenbergMarquardt. When combined with the GA, the dependency of such conventional algorithms to the initial guess is reduced and the overall regression performance is improved. For automated interpretations where the model is already known this method allows to virtually eliminate the initial guess determination step.

Tests on real and synthetic pressure transient data indicated that the proposed method was able to select the correct reservoir model. The method revealed hidden implications of the pressure transient that may otherwise have been overlooked due to noise. As a preprocessor for more conventional nonlinear regression approaches, applying GA to a number of noisy pressure transient tests demonstrated that the method is robust and efficient.
Characterization of Fractures/Faults Network from Well Tests; Synergistic Approach
Authors: Al-Thawad Faisal , Bin-Akresh Saud , Al-Obaid Rashid
Published: December 2007

In this paper we demonstrate the successful identification of a new flow problem of an intersected natural fracture connected to (or near) a finite conductivity fault. In a previous paper, finite conductivity faults in connection with high permeability layers were identified in mature parts of Ghawar field(1).

Four field cases are presented in this paper; a slanted well intersecting a fracture, a well close to a finite conductivity fault and a combination of the two. In the latter case, two examples of a fracture behavior at early times and a finite conductivity fault behavior at late times were identified. Because of the complex nature of these flow problems, numerical simulation along with all available data was integrated including 3D seismic to match the pressure response.
Transient Dual Porosity Behavior for Horizontal Wells: Case Histories
Authors: Verga F. M. , Beretta E.
Published: December 2007

Occurrence of bilinear flow regime in various geological situations has been discussed rather extensively in the literature. In particular, it was theoretically demonstrated that the bilinear flow regime can arise in the case of horizontal wells draining fractured reservoirs due to transient dual porosity behavior originating during the intermediate linear flow period. The bilinear flow regime can be identified by analysis of the well transient pressure response as the pressure derivative exhibits the characteristic quarter slope on the loglog diagnostic plot. However, the duration of the transient dual porosity behavior depends on the system geometry, namely location and length of the horizontal well and thickness of the producing layer, and on the permeability contrast which reportedly exists between the more conductive fractures and the feeding matrix. Three interesting case histories are presented in this paper where the pressure derivative response for horizontal wells drilled in different fractured reservoirs indicated the occurrence of the transient dual porosity behavior before that the linear flow, which is typical of horizontal wells in homogeneous reservoirs, was achieved. In agreement with the geological surveys it was interpreted that the bilinear flow was caused by two intersecting fracture systems showing a strong permeability contrast whereas the feeding action of the matrix, if any, could only be detected at a later time. In two cases clear evidence of pseudo steady state dual porosity behavior, indicated by the distinctive inflection in the derivative pressure response, was also observed, thus confirming the proposed well test interpretation. Several parametric analyses are also presented to define the geometrical and petrophysical conditions under which evidence of the bilinear flow regime can be expected.
Field Examples to Bridge the Gap Between Production Engineering and Reservoir Engineering
Authors: Su H-J. , Al-Rasheedi S.
Published: December 2007

Often time when a production engineer conducts a nodal analysis, he assumes a constant reservoir condition. Typically, a downhole shut-in static pressure will be taken as the reservoir pressure. In this work, we will demonstrate the importance of using reservoir simulation to model reservoir dynamics in conjunction with other production engineering tools.

The integration has helped us identify the cause for an extremely high skin generated from a short-term water injectivity test. Without reservoir modeling, we cannot be sure if the skin was from fine-particle plugging, or clay expansion, or wellbore debris accumulation. Interestingly, the build-up pressure derivatives were quite different prior to and after 1991. This discrepancy was explained by a partial blockage of one sand layer that was generated by an invading cement mixture during fire fighting after the Gulf war.

Another example shows use of production logging to solve a puzzle for a reservoir engineer. There is a vertical well and an expanding secondary gas cap has surrounded its upper portion. Its GOR value has been surprisingly low. The findings from production logging also help us characterize the geology around this well.

Using real examples, we show how to build synergy between reservoir engineers and production engineers. This work demonstrates the usefulness of reservoir simulation to help production engineers diagnose well operation problems.
A Newly Designed Electronic Memory Gauge Improves Reservoir Characterization
Authors: Azari M. , Fraser C. , Kool H. , Soliman M. Y.
Published: December 2007

This paper presents a new quartz electronic memory gauge that has been introduced to the oil industry. This gauge can record data with more precision than existing gauges, and thus, can establish more accurate flowing and shut-in pressure with higher resolution. In addition to describing the gauge design, this paper will also discuss the advantages of improved gauge resolution in the analysis of well test data and in determination of the hydrocarbons in place. The impact of using a higher resolution gauge on well testing is illustrated through analysis of field data.
Integrated Simulation of Reservoir, Gas Plant, and Economics for A Rich Gas Condensate Reservoir
Authors: Wang S. W. , Ringe D. P. , Gable M. M. , Staples D. J.
Published: December 2007

In the development of a rich gas condensate reservoir, a surface separator alone is usually not enough to condense all the heavy components from the produced well stream. A gas plant is required to extract the heavy components still remaining in the separator effluent gas. The operation can be further complicated by reinjecting the produced gas in order to control pressure decline rate and maximize condensate production. This work presents a method in reservoir simulation which significantly improves the history matching of condensate production and an algorithm which can be used to determine the concentration of individual components from the composition of pseudo-components. The achievements of this study include (1) the correct simulation of the composition and quantity of reinjected gas and wet inlet gas to gas plant, (2) the correct simulation of C3 spike due to lean oil absorption unit, (3) a workable algorithm to bridge reservoir and gas plant simulation at each time step, (4) rapid turnover time for each scenario by integrating reservoir, gas plant and economics into a single loop as opposed to three separate, unconnected simulation studies.