bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Improvement of Heavy-Oil Recovery by Using Electromagnetic Heating
Authors: Carrizales M. A. , Lake Larry W. , Johns R. T.
Published: September 2008

Heavy oil is produced primarily by reducing its viscosity using well-known processes such as steam injection, steamsoak, and in situ combustion. A recent technique for recovery consists of resistively heating the reservoir using electrical energy. Resistive heating can be particularly beneficial for reservoirs in which conventional steam operations are uneconomic.

Resistive heating is a special case of a more general form of heating based on electromagnetic energy (EM). EM has the following advantages over steam injection: it can be used to recover extremely heavy hydrocarbon, is not susceptible to heat losses through a wellbore, and its water requirements are far less than for steam. Compared to resistive heating, EM heats within the formation. Thus (for downhole generation) larger well spacing may be possible.

Although its potential was recognized in the late 70's, there are relatively few field applications of EM heating and even fewer engineering studies. The purpose of this paper is to examine how the performance response of EM compares to resistive heating.

This paper presents a model for single-phase flow to calculate the temperature distribution, and the productivity improvement obtained when an EM heating source (an antenna) is placed in a well. We consider both counter-current flow, in which the well with the antenna is also a producer, and co-current flow where the flow is opposite to EM energy flow. Flow is taking place concurrently with the addition of EM energy.

Steady-state solutions for counter-current flow showed a relative productivity index (PI) increase of 2.5 - 12.0 times cold oil production when the input power was varied from 20 to 150kw. A peak improvement occurred when the adsorption coefficient was between 1e−3 and le−1 m−1, which indicates that there is an optimum adsorption coefficient. Resistive heating is the special case of an infinite adsorption coefficient and the existence of an optimum suggests that EM heating can be more effective than resistive heating. For co-current flow, the improvement was even greater for the same input power. Calculated energy gains (the ratio of produced to injected energy) were in the 8 to 163 range; successful steam injection processes have gains of around 10.
Active Management of Five-Spot Water Flood Based on Continuous Reservoir Monitoring
Authors: Thigpen B. L. , Sakowski S. A. , Wang X. , Liu X. , Lee J.
Published: September 2008

Recently, the industry has seen an enormous increase in the amount of upstream data delivered with fine resolution and accuracy as provided by downhole monitoring equipment. Downhole measurements include distributed temperatures along the wellbore, wellbore pressure and temperature at discrete points, zonal flow rates, equipment performance data such as ESP operating efficiency, and downhole and surface chemical injection data. Even though the potential benefits of these measurements are recognized, practical models and processes that take full advantage of the actual data have not been well established.

Intelligent wells are gaining momentum in the oil and gas industry for production optimization, but utilization of this technology is limited to a single well or small group of wells, addressing somewhat localized optimization. Ultimate production optimization achieves higher reservoir recovery through incremental hydrocarbon production, and it needs a higher view than a well-centric approach. Considering that multiple intelligent wells comprise an intelligent field, all the data coming from each intelligent well should be brought together as input for a global optimization. This is analogous to bringing a fuzzy picture of a puzzle into focus as all the pieces fall into place. Similarly, to optimize a 5-spot waterflood, each well in the pattern should be intelligently controlled all the time and, in addition, they need to be optimized relative to each other so that the flood front movement is managed for maximum sweep efficiency. Optimization at this level is accomplished through an integrated use of reservoir/well modeling and real time data acquired through continuous downhole measurements. Measured data enables active model tuning, which in turn improves ongoing reservoir performance prediction. Sensitivity analyses find the optimal configuration of the intelligent wellbore components in injection and production wells that enables active waterflood front control.

This paper discusses methodologies used for the control mechanism, including a simplified reservoir model, continuous monitoring data, and a multi-well optimization process. Visualization and control of water flood efficiency, continuous tuning of the reservoir/well model, improved performance prediction and full utilization of real time data are some of the benefits from the process developed.
Debottlenecking and CFD Studies of High and Low Pressure Production Separators
Authors: Lee Joseph M. , Khan Rafiqul I. , Phelps Daniel W.
Published: September 2008

Efficient and effective oil/water/gas separation is required for success of many production operations. A major oil producer was experiencing difficulties with the oil/water/gas separation equipment on an offshore platform and improvements were required to meet both present and future production rates. Both HP and LP Separators on a major oil production platform were studied to determine the design limitations for foamy service and BS&W levels. CFD studies were completed to show the volumetric utilization and flow pattern improvements made with the design changes.

Both HP and LP separators showed substantial foam and poor efficiency due to poor inlet device design, plugging and other general vessel design limitations. Debottlenecking efforts determined that while the inlet device was somewhat ineffective, major improvements could be made from changes to perforated plate baffles, fluid level adjustments and weir placement and operations.

CFD calculations performed on both vessels indicated similar problems. The perforated plate baffles with improper design lead to counter current flow through the baffles making them less effective in flow control and distribution. Fluid level settings for the weir height affected the velocity differences between fluid layers and contributed to promotion of recirculation within the vessel, which lead to low volumetric utilization.

With adjustments to vessel internal equipment and changes to fluid phase levels, CFD calculations showed that overall vessel volumetric utilization was improved by 22% for the HP vessel and by 38% for the LP vessel. CFD results also showed the changes to the flow patterns accompanying these improvements.

Vessels with the proposed changes were operating effectively with substantially higher throughputs and meeting the expected BS&W levels for operations of the downstream oil processing equipment. Details about the vessel internals, flow properties and other changes required to accomplish these improvements will be discussed.
Anisotropic Stress Models Improve Completion Design in the Baxter Shale
Authors: Higgins Shannon , Goodwin Scott , Donald Adam , Bratton Tom , Tracy George
Published: September 2008

In unconventional reservoirs, stress models that account for anisotropy yield a stress profile which better represents in-situ conditions than the profile suggested by an isotropic stress model. Completion designs based on an accurate petrophysical model and stress profile which quantifies containment, influences perforating and staging strategies. This can help improve stimulation coverage from discreet shale intervals and lead to more economic completion decisions. This paper shows a comparison of stress magnitude estimated with a traditional linear poroelastic model from sonic data, with stress magnitude estimated from a model which accounts for transverse isotropy. A case study from the Baxter Shale play will show static and dynamic elastic moduli measured from core and acoustical logging, which vary significantly when measured in both the vertical and horizontal directions. The resultant stress profile estimated with a stress equation which accounts for this anisotropy better characterizes subtle stress changes that are significant for staging and perforating design in unconventional gas plays such as the Baxter Shale.
Advanced Wells: How to Make a Choice between Passive and Active Inflow-Control Completions
Authors: Birchenko V. M. , Al-Khelaiwi F. T. , Konopczynski M. R. , Davies D. R.
Published: September 2008

Horizontal and multi-lateral wells allow oil and gas companies to maximise contact with reservoir quality rock in either a single reservoir or multiple reservoirs. However they do not, by themselves, guarantee optimum reservoir drainage. Premature water or gas breakthroughs frequently occur due to: Reservoir permeability heterogeneity,Variations in distance between the wellbore and the fluid contacts, particularly in compartmentalized reservoirs,Variations in reservoir pressure in different regions of the reservoir penetrated by the wellbore.Pressure drop along the completion's flow path due to friction ("heel-toe" effect).

Many such well and reservoir management problems can be mitigated by installation of downhole flow control devices – "Active" Interval Control Valves (ICVs) and "Passive" Inflow Control Devices (ICDs). ICVs were initially employed for controlled, commingled production from multiple reservoirs; while ICDs were developed to counteract the "heel-toe" effect. The variety of reservoir applications for both technologies has proliferated so that their application areas now overlap. Appropriate selection between an ICV and an ICD completion can be both a complex and a time consuming process.

This paper compares the functionality and applicability of the two technologies. Completion Design selection guidelines are developed based on multiple criteria drawn from reservoir, production, operation and economic factors. Reservoir engineering aspects, such as uncertainty management, formation heterogeneity, and the level of flexibility required by the development are analyzed. Production and completion characteristics, such as tubing size, the number of separately controllable completion zones, the installation of multiple laterals and the value of real time information were also investigated. This systematic analysis forms the basis of a screening tool to identify the optimum technology for each particular situation.

This study provides a robust, comparative framework for both production technologists and reservoir engineers to select between passive and active flow control for optimised, advanced well completions.
Impact of Reservoir Uncertainty on Selection of Advanced Completion Type
Authors: Birchenko V. M. , Demyanov V. V. , Konopczynski M. R. , Davies D. R.
Published: September 2008

Well performance prediction is a key Petroleum Engineering task. However, large discrepancies between Petroleum Engineering models and reality still frequently occur; despite the continuous increase in the complexity and predictive quality of reservoir models. To-day's field development decisions are still made with a high level of uncertainty in the underlying data and its economic impact.

The degree of data uncertainty is greatest during the exploration stage, but decreases as the reservoir development plan is executed and production data is obtained. Standard, probabilistic workflows have been developed to quantify this uncertainty. These workflows are usually framed by the reservoir scale development plan and end prior to the well's detailed completion design. This is despite the fact that expensive, advanced completions have become common during recent years and the additional investment in such completions can only be justified if it is shown to be paid-back by improved overall project economics which is subject to a significant level of uncertainty.

This paper illustrates the quantification of the long-term benefits of advanced completions using the probabilistic approach. It will be shown how choice of the optimum advanced completion design will reduce the impact of geostatistical uncertainty on the production forecast. Geostatistical realisations of a benchmark reservoir model were generated with a suitable level of data uncertainty. The reservoir was developed by a single horizontal well in a fixed location. The well could be equipped with a variety of completions – an Open Hole with a sand control screen or a perforated pipe, Inflow Control Devices (ICDs) and Interval Control Valves (ICVs).

The probabilistic (P10, P50, P90) oil-recovery distribution was then used to identify the optimum completion design. This completion not only achieved the largest recovery, but also showed the least uncertainty in this value.
A New Compositional Model for Hydraulic Fracturing With Energized Fluids
Authors: Friehauf Kyle , Sharma Mukul M.
Published: September 2008

Traditional fracturing models regard fracturing fluids as a single-component, single-phase fluid. This assumption is clearly incorrect for energized fluids, where phase changes and mass transfer between phases play important roles in controlling fluid rheology, leak-off, and fracture geometry. A model is developed to simulate hydraulic fracturing with energized fluids. Compositional balances allow us to track the changes in phase behavior and fluid properties such as rheology and multi-phase leak-off. An energy balance is implemented in order to consider temperature changes during fracturing. Phase behavior has been taken into account through an equation of state formulation. These compositional and phase behavior effects are coupled with a geo-mechanical model for fracture propagation.

It is shown that phase behavior and leak-off can significantly change the composition and fluid rheology in the fracture. This has a dramatic effect on the fracture geometry. Phase behavior changes are closely coupled to the temperature and pressure changes in the fracture. The temperature, phase behavior, and partitioning of components in the liquid and gas phases have a significant effect on fracture dimensions. For example, shorter and wider fractures can be obtained by foaming an energized fluid. With the model presented, these temperature, pressure, and composition changes can now be accurately modeled and incorporated into the fracture growth and geometry.
Global Challenges Facing the Health, Safety and Environmental (HS&E) Function Within the Oil and Gas Industry
Authors: Bradish Ray , Bui Jonathan , Nunez Yolanda
Published: September 2008

Understanding legislative barriers, communication challenges, and business governance issues are just a slice of what lies ahead for many oil and gas companies choosing to expand their businesses into other areas of the world over the next decade, specifically Russia, China, and India. This paper addresses the challenges of migrating North American and European HS&E management systems, including HS&E personnel, into these domains that historically have not placed HS&E as a core element of business success.

HS&E programs that have demonstrated success in North American markets due to strict government regulations and commitment from corporate management will be faced with new cultures, behavioral challenges, and limited HS&E legislation. In the past, an HS&E professional working in the US or Canada primarily focused on the various elements of HS&E regulatory compliance they may have faced from labor unions, EPA, OSHA, DOT, Transport Canada, etc. This compliance effort seemed insurmountable at times due to the ever-changing bureaucracy from the respective governments in the US and Canada; however, these challenges are miniscule compared to what lies ahead for HS&E professionals supporting global operations. The new breed of HS&E professionals will need to be internationally schooled in many different HS&E country requirements, languages, and customs. Additionally, the largest challenge may be in behavioral transformation relative to understanding risk taking and the mindset of being unbreakable.

How will these challenges be met by companies planning to do the majority of their business in these particular countries? What impact will North American standards have in these countries and how will American and Canadian companies handle resistance to their way of managing HS&E programs abroad? Will organizations like the American Society of Safety Engineers, National Safety Council and the Board of Certified Safety Professionals have any global impact over the next decade? Clearly, these organizations need to have improved global exposure and participation in order to have a positive change in HS&E development. This paper discusses how global oil and gas producers and service companies need to challenge the regulatory bodies of these countries to implement HS&E processes similar to those in North America.
Predicting Hydrate Plug Formation in a Subsea Tieback
Authors: Davies Simon R. , Boxall John A. , Koh Carolyn A. , Sloan E. Dendy , Hemmingsen Pål V. , Kinnari Keijo J. , Xu Zheng-Gang
Published: September 2008

Field data from StatoilHydro on hydrate plug formation in the Tommeliten gas condensate field are compared to predictions of the hydrate growth model (CSMHyK-OLGA) for four typical operating scenarios: 1. steady state operation with failure of inhibitor injection, 2. restart of an uninhibited line, 3. restart of an under-inhibited line and 4. restart of a depressurized line.

Although the CSMHyK model was designed for oil flowlines, the model is able to predict the correct timescale for hydrate plug formation in this gas condensate tieback. The predicted locations of the plugs are often further upstream than observed in the field trials. This is mainly due to the assumption of a "hydrate-oil slip factor" of zero, which forces the hydrate to accumulate where it initially formed. In reality hydrate agglomerates would be carried further downstream before eventually jamming in dips.

Predicting where and when hydrate plugs will form in subsea tiebacks is of increasing importance as the industry strives to manage the risk of plugging in oil and gas flowlines while minimizing the use of costly and environmentally harmful chemicals for hydrate inhibition. The Colorado School of Mines has been developing the CSMHyK model for the past five years in collaboration with the SPT Group and several leading energy companies.
Solving Swelling Clay Issues: Drilling With Expandable Reamers in WBM Reduces Trip Time by 66%, Argentina
Authors: Bazzara Hugo , Biasotti Hugo , Romero Angel , Crovetto Marcelo , Pinheiro Cezar
Published: September 2008

The Chihuido de La Salina field is located in the folded thrust belt of the Neuquén Basin in west-central Argentina, about 200 kilometers northwest of the city Neuquén (Figure 1). The field contains several fault blocks, which produce both oil and gas. Generally, production is controlled by a thrusted anticline, structurally high in the north and relatively low to the south. The most important portion of the field produces oil from the steeply dipping flanks. Efficiently drilling the swelling clay formations of the Neuquén group (Upper Cretaceous), in Chihuido de La Salina field (ChLS), has been a distinctive challenge and is the subject of this paper's analysis and multiple-well case studies.
Slickwater Fracturing - Food for Thought
Authors: Palisch T. T. , Vincent M. C. , Handren P. J.
Published: September 2008

The evolution of fracturing technology has provided the industry with numerous advances, ranging from sophisticated fluid systems, to tip screen out designs, to propagation modeling. Interestingly, these advances have typically been focused on ‘conventional’ designs which utilize a cross-linked fluid system. However, as the development of unconventional (tight gas, shales, coal-bed methane etc) or underpressured reservoirs has increased, so has the demand for innovative hydraulic fracture designs. The most recent of these design changes has been the popular method of placing proppant with slickwater, linear gel or hybrid treatments.

Although our industry has significant expertise in fracture design, most of our experience has been in conventional cross-linked fluid systems. However, there are many aspects of cross-linked fluid design that either do not apply to slickwater treatments, or in some cases are exactly opposite.

This paper will begin by reviewing the motivation, benefits and concerns with slickwater fracturing, and discuss why this seemingly ‘old’ method has regained popularity over conventional cross-linked designs in many reservoirs. In addition, the authors will detail some of the important theories related to slickwater fracturing, including fracture width and complexity, proppant transport and settling, and conductivity requirements. In each case, emphasis will be placed on the different strategy that must be employed compared to cross-linked fluid designs, and highlight the mistakes or misunderstandings that are frequently made.

Where appropriate, lab testing, field measurements, reference material and other resources are presented to support the observations made by the authors. This paper will serve as a resource to any engineer or technician who is designing/pumping slickwater fracs, or who is considering this technology for potential application. By applying the concepts presented in this paper, engineers will be able to appropriately evaluate the potential benefits of using this technique in their completions, as well as draw on the experiences of others to take full advantage of this technology.
Improved Recovery in Gas-Condensate Reservoirs Considering Compositional Variations
Authors: Shi Chunmei , Horne Roland N.
Published: September 2008

The objective of this work was to develop a methodology to increase the productivity of gas/condensate from gas-condensate reservoirs. Presently, gas-condensate reservoirs experience reductions in productivity by as much as a factor of 10 due to the dropout of liquid close to the wellbore. The liquid dropout blocks the flow of gas to the well and lowers the overall energy output by a very substantial degree. The combination of condensate phase behavior and rock relative permeability results in a composition change of the reservoir fluid, as heavier components separate into the dropped-out liquid while the flowing gas phase becomes lighter in composition. This effect has been sparsely recognized in the literature, although there is clear evidence of it in field observations. This work quantified the effect, developed a scientific understanding of the phenomena, and used the results to investigate ways to enhance the productivity by controlling the liquid composition that drops out close to the well. By optimizing the producing pressure strategy, it should be possible to cause a lighter liquid to be condensed in the reservoir, after which the productivity loss would be more easily remedied.

The research made use of experimental measurements of gas-condensate flow, as well as compositional numerical simulations. Different strategies have been compared, and the optimum producing sequences are suggested for maximum condensate recovery. Results show that composition varies significantly as a function of fluid phase behavior and producing sequence; condensate recovery can be improved with proper producing strategy, and productivity loss can be reduced by changing the producing sequence.

This study can be used to determine the optimum producing strategy when the well is brought into production and reduce the productivity loss caused by the condensate banking effect.
CO2 Injection for Enhanced Gas Recovery and Geological Storage of CO2 in the Long Coulee Glauconite F Pool, Alberta
Authors: Pooladi-Darvish Mehran , Hong Huifang , Theys Sophie , Stocker Rudi , Bachu Stefan , Dashtgard Shahin
Published: September 2008

Impure CO2 containing less than 2% H2S has been injected since 2002 into the depleted Long Coulee Glauconite F gas Pool in southeastern Alberta. Breakthrough was observed within one to three years in producing wells, leading to their abandonment. Simulation studies reported in this paper indicate that additional gas was recovered as a result of CO2 injection. An interesting observation at the breakthrough wells was that the CO2 broke through ahead of the H2S. The partitioning of the H2S and CO2 as they flow through the reservoir was studied in detail. One objective of the reported work is examination of interactions of the injected gas with the in-situ fluids and the displacement of the in-situ gas by the injection gas, for better understanding of the mechanisms involved in enhanced-gas recovery. Another objective of the work is to study factors that affect the spread of the injected gas in a depleted oil and gas reservoir and its implications with respected to CO2 geological storage. The results of this study indicate that at low pressures, the injected gas occupies a large reservoir volume and exhibits little density difference with the in-situ fluids, leading to rapid spread of the injected gas and early breakthrough. Also, it was found that in the case of Long Coulee Glauconite F gas Pool the well-spacing used for production did not allow a detailed geological characterization that was required for accurate prediction of breakthrough as a result of gas-gas displacement. Simulation studies, together with displacement experiments in the laboratory reported elsewhere, confirmed that the preferential solubility of H2S in the reservoir water led to stripping of the H2S at the leading gas front and it delayed its breakthrough relative to that of CO2. The implications of such chromatographic partitioning of H2S and CO2 in geological storage of impure CO2 streams are discussed.
Modeling Reservoir Temperature Transients and Matching to Permanent Downhole Gauge Data for Reservoir Parameter Estimation
Authors: Duru Obinna , Horne Roland N.
Published: September 2008

Permanent downhole gauges (PDGs) provide a continuous source of downhole pressure, temperature and sometimes rate data. Until recently, the measured temperature data have been largely ignored. However, a close observation of the temperature measurements reveals that the temperature responds to changes in flow rate and pressure, which implies that the temperature data may be a source of reservoir information.

In this work, the Alternating Conditional Expectations (ACE) technique was applied to temperature and flow rate signals from PDGs to establish the existence of a functional relationship between them. Then, performing energy, mass and momentum balances, reservoir temperature transient models were developed for flow of single- and multiphase fluids, as functions of formation parameters, fluid properties, and changes in rate and pressure. The pressure fields in oil and gas bearing formations are usually transient. This gives rise to pressure-temperature effects appearing as temperature changes in the porous medium when the pressure field changes. The magnitudes of these effects depend on the properties of the formation, flow geometry, time and other factors and result in a reservoir temperature distribution that is changing in both space and time. Therefore, in this study, reservoir thermometric effects were modeled as convective, conductive and transient phenomena with consideration for time and space dependencies. This mechanistic model included the Joule-Thomson effects due to fluid compressibility, and viscous dissipation in the reservoir during fluid flow in accounting for the reservoir temperature dependence on changing pressure/flowrate fields.

Numerical solution schemes as well as the semianalytical scheme – Operator Splitting and Time Stepping (OSATS) were used to solve the models, and the solutions closely reproduced the temperature profiles seen in real measured data. By matching the models to different temperature transient histories obtained from PDGs, reservoir parameters namely porosity and saturation and fluid Joule-Thomson coefficient could be estimated. Hence the normally unused temperature data record can be used to estimate reservoir parameters not usually available from conventional well test analysis. Analysis of temperature may also provide a less expensive substitute for downhole flow rate measurement.
A Multiresolution Analysis of the Relationship between Spatial Distribution of Reservoir Parameters and Time Distribution of Data Measurements
Authors: Awotunde Abeeb A. , Horne Roland N.
Published: September 2008

An important issue in reservoir parameter estimation is to develop computationally efficient and reliable nonlinear regression procedures. We present a multiresolution wavelet approach to estimate spatial distribution of reservoir parameters, by performing the nonlinear least squares procedure in the wavelet domains of both time and space. Wavelet transforms have the ability to reveal important events in any signal or image. Thus we transformed both the model space and the data time into spatial wavelet and time wavelet domains and used a thresholding to select a subset of wavelet coefficients from each of the transformed domains. These subsets were subsequently used in the nonlinear regression procedure to estimate the appropriate subset of reservoir parameters. The appropriate subset is not only smaller and therefore more efficient computationally, the problem is also reduced to the consideration of only the important components of the measured data and only the part of the reservoir description that depends on them.

We applied the procedure to a radially composite reservoir system to demonstrate the reliability of the approach. The inverse problem was solved to estimate the distributed permeability values by performing the nonlinear least square regression in the wavelet domains (time and space).

Results obtained were compared to those obtained from the conventional nonlinear regression approach. The time-space wavelet approach proves to be more efficient computationally compared to the conventional approach. By reducing the dimensions of the model and data spaces the model stabilizes the algorithm and gives faster convergence. Significantly, the approach reveals the true number of reservoir parameters that can be appropriately estimated from a given data set.

The approach provides a good means to integrate different data properly while avoiding the inclusion of irrelevant data during nonlinear regression. The procedure also reduces the number of iterations needed for convergence.
A Semianalytical Thermal Multiphase Wellbore Flow Model for Use in Reservoir Simulation
Authors: Livescu S. , Durlofsky L. J. , Aziz K.
Published: September 2008

The detailed interactions between the reservoir and the wellbore are especially important in thermal processes such as steam flooding and in situ upgrading. These linkages must therefore be captured in thermal simulations. Although fully-coupled thermal wellbore-reservoir flow simulators have been developed, the implementation of the thermal well model is somewhat complicated and the simulations are computationally demanding. In this paper, we present a semianalytical treatment that enables a fairly straightforward extension of existing isothermal wellbore flow models to the nonisothermal case. The procedure entails the use of analytical solutions for wellbore temperature applied in conjunction with numerical solutions of the reservoir mass and energy balance equations coupled with wellbore mass and momentum balance equations. The approach thus enables a degree of decoupling between the wellbore flow and energy problems. We proceed by first presenting analytical solutions for wellbore temperature, developed under various assumptions (some of these solutions have been obtained previously). We then describe the use of one of these solutions, which allows for general variation of in situ phase fraction and other properties along the wellbore, within the semianalytical context. The implementation of the overall method into a general purpose research simulator is also described. Results are presented for several cases involving multiphase flow in monobore and multilateral wells. Close agreement with reference solutions, obtained from a fully-coupled thermal wellbore-reservoir model, is demonstrated for all of the examples. The semianalytical treatment is additionally shown to provide comparable or improved computational efficiency relative to the fully-coupled model. The overall procedure is therefore very well suited for use in general thermal reservoir simulation.
Risk Analysis as Decision Tool to Upgrade Aging Offshore Trunk Lines
Authors: Angibeaud L.
Published: September 2008

All over the world, the operation of old and aging pipelines, all potentially subject sooner or later to internal corrosion, raises concerns about the risk and the consequences of pipeline failures. With the exception of third party damages, most cases of failure are caused by internal and external corrosion. In Saudi Arabia Offshore Operations, old pipelines were originally designed for "dry" oil operations and constructed without scraping facilities. Therefore, the observation and monitoring of internal corrosion is virtually impossible without significant modifications. In new pipelines, facilities allowing the internal condition monitoring are included at the design stage. Indeed, loss of production and detrimental environmental impacts are less and less acceptable to society. They are indicators of poor performance in the public's opinion, and create costly business expenses.

Observations:

Saudi Arabian Offshore Operations operate a very large number of old pipelines for which intelligent scraping facilities have not been retrofitted. This upgrade requires very large capital expenditures and for that reason cannot be performed on every offshore line. To respond to the dilemma of either doing "nothing" or to invest a substantial amount of money without an absolute certainty of success, a risk analysis has been performed.

Approach:

Several alternative decision trees are developed to portray the decision process. The pipelines are analyzed based on the risk analysis described as: –Possible events which may occur during a pipeline's lifetime.–Investments and costs associated with the event described.–The cumulative risked capital and total risked capital.

Significance:

The risk analysis allows a comparison of different pipeline situations, and the analysis helps in building the business case to install intelligent scraping facilities. When the scraping scheme is applied, the investment increase is associated with a risk reduction in pipeline failure.
High Gas-Rate Production: Expandable Solutions in the Mediterranean Sea
Authors: Pierfelici Stefano , Tacconelli Antonella , Ripa Giuseppe , El Nagar Hesham Mahmoud , Bowen Eddie G. , Elsakhawy Tamer , Mohamed Omar Y.
Published: September 2008

An operator facing the need for sand control in multiple maturing fields investigated the possibility of using expandable technologies to address their needs. Years of production and the onset of water production has affected that need. After an extensive study of rock mechanics and properties and how sand production might be initiated based on these properties, the investigation for an optimized sand control technique began.

A systematic approach ensued between operator and Service Company in an attempt to define an optimized solution for sand control in each of these fields. Conventional cased hole gravel packs were excluded due to the need for a larger flow area for handling the high gas rates. Open hole gravel packing was investigated yet ruled out due the exposed unstable shales during the packing operations. Ultimately the optimized solution led to the deployment of an expandable screen system to ensure sand control for the remaining life of each well.

The undesirable shales were isolated with the installation of expandable blank pipe and expandable packers. Expandable screens were positioned across the clean sand bodies. Many wells had multiple sand bodies exposed. These separate reservoir sections were isolated with expandable blank pipe and packers as well. The entire expandable assembly was deployed in a single trip and hung off in the parent casing with an expandable hanger. Sand-free production data obtained from more than 20 wells will be presented and discussed.

Expandable technologies provided the operator with a sand control technique that previously didn't exist., After exploring this new technology, the operator conducted multiple installations of expandable sand screen for sand control in the maturing fields of the Mediterranean Sea. This became the new philosophy for sand control by the operator in the Mediterranean Sea as well as other parts of the world where they have sand control needs.
Multiple Reservoir Simulations Integration: An Alternative to Full Field Simulation in the North Kuwait Jurassic Complex
Authors: Ghorayeb Kassem , Limsukhon Manoch , Dashti Qasem , Aziz Rafi Muhammed
Published: September 2008

The North Kuwait Jurassic Complex consists of five fields, each with three identified reservoirs within the naturally fractured Jurassic carbonate formation. These reservoirs contain multiple fluid types at near critical conditions with flow properties ranging from fracture to matrix dominated flow. Multiple-scenarios production forecasts, using dual-porosity, dual-permeability reservoir simulation models, are required to prepare an optimal development plan for the complex.

In this paper we discuss available options to simulate multiple reservoirs which, although isolated based on the current compartmentalization understanding of the complex, they cannot be run in isolation because of global production targets. We show that using multiple-reservoirs integration through controller to couple the separate reservoir models through global production targets/limits provides an optimal simulation framework for the NKJC: flexibility and computational efficiency of multiple segment models and comprehensiveness of full filed simulation modeling.
Investigation of VOC Emission Control by the Use of Clay Aqueous Foams
Authors: Sani A. M. , Mohanty K. K.
Published: September 2008

During the process of crude oil/gasoline loading, significant amounts of volatile organic compounds (VOCs) can be emitted to the environment. Stable aqueous foam can be spread as a flexible blanket before crude oil/gasoline loading to control the VOC emission by providing a mass transfer barrier during the loading process. In this work, novel aqueous foams have been formulated by incorporating special type of clay nano-particles in an aqueous solution of surfactants and polymers. Experiments to investigate the foam stability and VOC emission were carried out in a bench-scale foam column. These foams are found to be very stable and can last much longer a day. There was a decrease of the rate at which liquid is drained out of the foam and thus, a decrease of the rate of quality increase. There is also a significant reduction of vapor emission for the first 40 hours. Increasing polymer and clay concentrations increases the foam stability and mass transfer resistance.
A Multistage MCMC Method with Nonparametric Error Model for Efficient Uncertainty Quantification in History Matching
Authors: Ma Xianlin , Datta-Gupta Akhil , Efendiev Yalchin
Published: September 2008

Uncertainty quantification is generally carried out in a Bayesian framework whereby multiple reservoir models can be evaluated by sampling from a posterior distribution that incorporates the observed production data and the prior parameter distribution. Rigorous sampling methods such as the Markov Chain Monte Carlo (MCMC) method provide accurate sampling but at a high cost because of their high rejection rates and the need to run flow simulation for every proposed candidate.

We propose a methodology that combines coarse- and fine-scale information to improve the efficiency of MCMC methods without loss of its rigorousness in sampling. Our proposed method employs off-line computations for establishing a mathematical relation between coarse- and fine-scale error responses. This relation is modeled using non-parametric approaches that correlate the error responses via optimal transformations. The resulting statistical models are then used in efficient sampling within an MCMC framework. We propose a multi-stage MCMC where inexpensive coarse-scale simulations are performed to determine whether or not to run the fine-scale simulations. The latter is determined based on the non-parametric error model developed off-line. Our proposed method substantially improves the efficiency of existing multistage MCMC methods that only rely on coarse-scale or other approximate models. Most importantly, our proposed method does not depend on the proximity of the coarse and fine-scale models and thus, can employ much coarser and inexpensive models to guide the fine-scale simulations.

We will present a synthetic and a field example involving three-phase flow to demonstrate that the proposed approach is both robust and computationally efficient. In these examples, water cut and GOR are integrated to generate multiple reservoir models and assess uncertainty in the production forecasts.
Integrated Geomechanical Study for Hole Stability, Sanding Potential, and Completion Selection: A Case Study From Southeast Asia
Authors: Khaksar Abbas , Rahman Khalil , Ghani Juanih , Mangor Hapiztuddin
Published: September 2008

A full scale geomechanical study was carried out to evaluate hole stability during drilling and production, and sanding potential of Lower Miocene oil bearing sands in horizontal wells with planned open hole completion in a Malay Basin field, offshore Malaysia. Drilling information, well logs and rock mechanical test results were used to determine in situ stresses, pore pressure and rock mechanical properties in the field. This paper highlights the use of geomechanics principles integrated with sound drilling and completion practices to achieve and deliver highly productive wells in the field.

An analytical 3D elastic-shear failure model and a 2D elasto-plastic yield zone growth model were used to evaluate the sanding risk over life of field conditions. Using conservative critical sand failure parameters, both the elastic and elasto-plastic sanding models indicate that the risk of sand production during the life of field would be very low to none; therefore, no sand control would be required for the planned horizontal wells. 2D elasto-plastic hole stability modelling, using Mohr-Coulomb failure criteria, showed that the sandstone sections should remain stable over the life of field in an open hole (barefoot) completion, even with water cut. However, the stability of intra-reservoir shales in a barefoot completion might be at risk under high reservoir pressure depletions, if no depletion occurs in shales.

Planned horizontal wells were drilled successfully with no major drilling problem by using the recommended mud pressures and good drilling practices, confirming the reliability of the geomechanical model and wellbore stability analysis. The wells were completed with predrilled liners to minimise the risk of hole instability in shales. The wells are currently producing sand free with the planned drawdowns while water cut is approaching 70%, confirming the accuracy of sand production predictions. Integration of geomechanical analysis with rational engineering judgment and practices resulted in avoidance of unnecessary sand prevention installations which could be expensive and have adverse effects on well productivity.
Public Perception of the Natural Gas Industry: Insights From Two Barnett Shale Counties
Authors: Theodori G. L.
Published: September 2008

Data collected in a general population survey from a random sample of individuals in two counties located in the Barnett Shale region of Texas were used to empirically explore issues associated with public perception of the natural gas industry. Moderate support was found for the hypothesis that individuals residing in places with diverse levels of energy development exhibit dissimilar perceptions of the energy industry. Bivariate and multivariate logistic regression analyses indicate that residents of the county where the natural gas industry is more mature (Wise County) exhibit somewhat more negative perceptions of the energy industry than do residents of the county where natural gas industry is less established (Johnson County). The results also reveal that mineral rights ownership is a relatively strong and consistent factor associated with public perception of the natural gas industry. Possible implications of these findings for the energy industry are proposed, as are suggestions for future research.
On the IPR Curves of Horizontal Wells in Solution-Gas Drive Reservoirs
Authors: Jabbari H. , Economides M. J.
Published: September 2008

Inflow performance relationship (IPR) curves have been extensively studied in the petroleum engineering community; from the classic Vogel's method for vertical wells to modified models for horizontal wells. Previous works have indicated that the performance of horizontal wells can be different from that in vertical wells due to their more complex geometries. Hence, this encourages us to aim for modified IPR correlations.

Modeling the production performance in a horizontal well requires an understanding of the parameters that may affect the fluid flow geometry and well/reservoir interface. In this work, numerical modeling was employed to study the performance of horizontal wells under different well/reservoir conditions. A new IPR relationship was proposed for horizontal wells producing from solution-gas drive reservoirs along with a modified absolute open-flow potential (AOFP) which was proposed initially by Kabir. This was to introduce new terms that accounted for the effect of bubble-point pressure and recovery factor which were found to be significant. The developed model was tested against field data, and it was also evaluated and compared with the current IPR curves.

In order to generate an IPR curve for a horizontal well at the specified recovery factor, simulation models were constructed and run for each bottomhole pressure. Then, computer codes were used to extract the results from each results file. Next, the coefficicents and parameters of the equations were obtained from non-linear regression and curve fitting. Then, IPR curves from the analytical model were generated at specified well/reservoir conditions, and at a certain recovery factors. Finally, the results from the model were compared to the simulation model and field data.

This work confirmed that the IPR curves in horizontal wells producing from a saturated reservoir may need modified relationships due to more cmplex flow geometry and well/reservoir interactions. The developed three-parameter IPR relationship presented reasonable accuracy as was compared to the currenmt models and field/simulation data. Also, the new AOFP equation showed a reasonable error of 3% compared to the simulation results.