bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Diversion of Acid Stimulation in Water Producing Oil Wells: Case Histories, Nisku Formation, Central Alberta
Authors: Henderson G. , Metcalf A. S. , Alderdice E.
Published: December 2007

Stimulation of carbonate oil and water producers with acid can result in an uneconomical increase in water production. This is the result of poor placement of the treatment stimulating the water-bearing rock preferentially to the oil. Typical treatments in the Nisku use selective tool isolation of zones to achieve the required placement control. The operational costs associated with this type of treatment make it difficult to perform economical stimulation treatments on marginal wells. Acid treatment of such a well, using only a diverting agent for control of placement, risks increased operational costs associated with possible increased water production and, therefore, the reduction of a marginal well to an uneconomical one.

A unique diverting material formed by the reaction of an aqueous solution of dibasic acids and rosin esters, with divalent cations, present in formation water or spent acid allows the selective stimulation of only the oil-producing zones. The reaction product is an oil-soluble precipitant. The oil-soluble nature of the diverter base materials and the resultant precipitants makes the likelihood of the precipitant forming in the oil zones remote; however, in the event of such a result, the produced oil will remove the precipitant.

Presented are laboratory tests describing the effectiveness of the oil-soluble material to divert acidic fluids away from water flows. Also, demonstrated is the subsequent cleanup of this oil-soluble diverting material using produced oil. In addition, several case histories from the Wayne area of Alberta, Canada are included. The results of these treatments demonstrate that control of acid placement in water-cut producers results in a considerable increase in oil production while minimizing the effect on water cuts. A significant reduction in the operational costs associated with switching from the selective tool isolation technique to the one described above is also demonstrated.
Simplified Method for Calculation of Minimum Miscibility Pressure or Enrichment
Authors: Yuan Hua , Johns Russell T.
Published: December 2007

Local displacement efficiency from gas injection is highly dependent on the minimum miscibility pressure (MMP) or minimum miscibility enrichment (MME). Analytical methods, which are inexpensive and quick to use, have been developed to estimate MMP's for complex fluid characterizations. Published methods,1,2,3 however, often require estimation of numerous parameters and little has been written with regard to method robustness. This paper presents a simplified and robust method for MMP or MME calculation.

The approach relies on finding key crossover tie lines for a dispersion-free displacement using method of characteristic theory (MOC). The new method, however, differs from published methods by significantly reducing the number of equations and unknown parameters, and by providing a fast and robust method that can avoid trivial and false solutions. We demonstrate the improvements by calculation of the MMP and MME for a variety of gas/oil systems and also give new analytical solutions for constant Kvalue systems that give insight into the nature of the false solutions.
Determination of Environmental Liabilities and Development of a Facility Closure Plan for a State Oil and Gas Company
Authors: Sookdeo Nigel
Published: December 2007

Good business practices by oil and gas operators require a responsibility to decommission uneconomic assets (wells, pipelines, structures) to prevent any ongoing environmental damage resulting from the improper abandonment and closure of all or any of its operations. With the introduction of the International Accounting Standards (IAS)-37 regulations for Contingent Assets and Liabilities, many oil and gas operators are now required to state current and past liabilities as a result of oil and gas exploitation, their current assets, and a phased closure plan for these assets when deemed uneconomic.

Prior to the introduction of the IAS-37 accounting standards, many operators ignored the concept of life cycle costing when developing and exploiting assets. The result was that provisions for the cost of decommissioning of assets when uneconomic were not originally factored into the economic analysis and accounting for major projects or field development. When an asset was spent, improper abandonment resulted in many operators being faced with environment, health and safety (EHS) liabilities and a strain on financial resources for abandonment that were not originally catered for.

Proper life cycle analysis and decommissioning of assets is crucial for regulatory compliance, due diligence, and reduction of internal and external liabilities. The requirement for the development of a facility closure plan includes (1) the identification of all areas of activity requiring closure, (2) the closure procedures and costs, and (3) the implementation of phasing of items identified for closure. Some of the benefits of a facility closure plan to an operator include the reduction of HSE risks, conformance with the IAS-37 standard, financial management, and internal asset management. Some of the challenges faced by an operator in developing a facility closure plan include the lack or unavailability of data, limited financial and human resources, limited technical data on oil and gas reserves, and the lack of environmental baseline data.

The intent of this paper is to highlight the requirements by operators to develop a "facility closure plan" and to determine the closure liabilities associated with the implementation of that plan that would conform to International Accounting Standard-37 and accepted business practice. Reference will be made to the efforts of Petrotrin-Trinmar S.B.U., an oil and gas operator in Trinidad and Tobago in the development of a facility closure plan for all areas of operation.
Quantification of Multi-Phase Fluid Saturations in Complex Pore Geometries from Simulations of Nuclear Magnetic Resonance Measurements
Authors: Toumelin E. , Torres-Verdin C. , Chen S.
Published: December 2007

We develop a numerical algorithm to simulate nuclear magnetic resonance (NMR) measurements in the presence of constant magnetic field gradients. The algorithm is based on Monte Carlo conditional random walks in restricted and unrestricted space. Simulations can be performed of threedimensional (3D) porous media that include both arbitrary bimodal pore distributions and multi-phase fluid saturations. The ability to account for the presence of a constant external magnetic field gradient allows us to replicate actual well logging conditions that include the effect of CMPG pulse sequences at a microscopic level. This is accomplished by simulating pulse acquisition techniques that include multiple inter-echo times (TE) similar to those currently used by the well-logging industry. Benchmark examples are presented to validate the accuracy and internal consistency of our algorithm against previously published results for the case of a null magnetic field gradient. Validation examples are also presented against actual NMR measurements performed on core samples of carbonate rock formations.

Interpretation work is focused to the petrophysical assessment of both partial oil/water saturations and pore structures exhibiting hydraulic coupling. Simulation examples are designed to quantify whether the inclusion of diffusion under a magnetic field gradient can improve the interpretation of multi-phase fluid saturations when hydraulic coupling is significant. The simulation algorithm sheds light to new NMR data acquisition strategies that could be used to improve the detection and quantification of (a) fluid types, (b) complex fluid saturations, and (c) complex pore geometries.
PVT Sampling With Multiphase Flowmeters—Theoretical Justifications and Field Limitations
Authors: Jayawardane S. , Theuveny B. C.
Published: December 2007

Multiphase flowmeter technology probably is the most significant innovation in surface well testing in more than 30 years. Multiphase flow measurement is becoming a globally accepted technique for well and reservoir performance evaluations. The qualification of the validity of samples collected during these operations is required to validate the full potential of multiphase well testing techniques.

This paper discusses the new methodology developed for collection of samples using dual-energy spectral gamma ray Venturi multiphase flowmeter technology in field operations. The paper presents some of the theory and assumptions underlying multiphase flow computations and valid sample collection with the flowmeter. Field operations are detailed in the paper and provide operational guidelines to improve safety and optimize sampling operations. A description of the laboratory pressure/volume/temperature (PVT) analysis procedures required to physically recombine these nonconventional gas and oil samples is provided, and a series of field examples illustrate the efficiency of using multiphase flowmeters for well testing.

A sensitivity analysis is conducted for various gas and oil sample recombinations and resulting PVT properties computed by equation of state-(EOS-) based compositional simulations. The parameters considered are possible variations in sampling temperature or pressure and their impact on the resulting recombined fluid PVT properties.
Connecting Laboratory and Field Results for Gelant Treatments in Naturally Fractured Production Wells
Authors: Marin Amaury , Seright Randy , Hernandez Maria , Espinoza Maria , Mejias Fanny
Published: December 2007

This paper demonstrates the connection between laboratory measurements and field results from gelant treatments in production wells at the naturally fractured Motatan field in Venezuela. Using a HPAM polymer with an organic crosslinker, laboratory corefloods revealed that under reservoir conditions, the gel provided oil and water residual resistance factors of 20 and 200, respectively. This gel was placed in several production wells in the Motatan field. In Well P-47, 1,000 bbl of this gel reduced the water cut from 97% to 64% and increased the oil production rate by 36%. The success of these treatments depends on the distance of gelant leakoff from the fracture face and the in situ residual resistance factors in the oil and water zones. Analyses were performed to determine these parameters, based on formation permeabilities, porosities, fluid saturations, fluid properties, fluid production rates, and pressure drops before, during, and after gelant placement. Accurate pressure drops before, during, and after gelant placement were particularly important. Sensitivity studies were performed to demonstrate their significance and the impact of measurement errors. A methodology is presented for optimizing the volume of gelant injected for these applications.
Comparing Production Responses from Devonian Shale and Berea Wells Stimulated with Nitrogen Foam and Proppant vs. Nitrogen-Only, Pike Co., Kentucky
Authors: MacDonald R. J. , Frantz J. H. , Merriam G. W. , Schlotterbeck S. T.
Published: December 2007

This paper presents results of a production data comparison and an economic analysis of two stimulation methods (nitrogen foam with proppant versus nitrogen only) pumped in more than 200 wells owned and operated by Equitable Production Company. The wells, located in Pike County, Kentucky, were completed in the Berea and Devonian shale formations, and each formation was stimulated separately. About half the wells were stimulated with nitrogen foam containing proppant; the other treatments consisted of nitrogen only.

These wells were drilled in the 1990s and sufficient production data were available to make definitive comparisons. The results indicated that the wells treated with foam containing proppant significantly outperformed the wells treated with nitrogen only. Economic results also illustrated that it is more profitable to pump nitrogen foam with proppant even though the cost of the treatment is more than double.

In furtherance of this study, the operator is currently pumping foam with proppant in wells within the study area and is identifying additional acreage for use of this stimulation treatment. Existing wells are also being evaluated for restimulation potential. The results of this paper are noteworthy for the Appalachian Basin because many operators pump multiple stages of nitrogen-only treatments.
Estimation of Underground Blowout Magnitude Using Temperature Logs
Authors: Ipek G. , Smith J. R. , Bassiouni Z.
Published: December 2007

Temperature logs can be used to identify entry and exit points of underground blowouts. The magnitude of the flow can be estimated using relationships that are applicable after a flow time of several days. However, the ability to estimate the flowrate as soon as the blowout is detected is critical for the selection and design of a kill method.

A model relating underground blowout rate and the flowing fluid temperature that is valid for short flow-time was derived. The model uses transient radial heat transfer conditions from the wellbore to the surrounding rock and constant heat transfer coefficient inside the well. Application of the method is illustrated for several hypothetical and two real field examples.
Case Study: Combining Pulsed Neutron Spectroscopy and LWD Resistivity for Analysis Behind Casing in Small Holes.
Authors: Beaumont-Smith N. , Webber G. D. , Shepherd P. J. , Kalyanaraman R. S.
Published: December 2007

Formation analysis from behind casing is gaining more relevance in assessing reservoirs not only in ageing fields but also in new wells completed without the full complement of openhole petrophysical measurements or with openhole measurements of inadequate quality. Before this technology was available, formation evaluation in freshly drilled holes was dependent on the availability of openhole log measurements. This paper discusses field examples where reservoirs were evaluated without a full suite of openhole log measurements. Examples from two sidetracks in a mature North Sea field supported by water injection are presented. The small hole size limited openhole data acquisition to resistivity and gamma ray, which were acquired using logging-while-drilling (LWD) technology.

In both cases pulsed neutron (PN) measurements were recorded through casing to augment the existing data. Porosity and formation sigma (macroscopic thermal neutron capture cross-section) measurements were obtained. Fluid saturations were computed using this porosity and the LWD resistivity. Saturations were also computed from the carbon-oxygen measurement and these agreed with the resistivity-based answers. Lithology analysis was performed using elemental spectral capture yields and was reliable and consistent field wide.

The results show that in a mature oil field, PN measurements can provide a complete lithology and saturation analysis in circumstances where insufficient openhole petrophysical measurements are available.
Hierarchical Organization of Flow Network in Fractured Carbonate Reservoirs: Identification and Characterization of Key Parameters
Authors: Massonnat G. , Viszkok J. , Vrignon M.
Published: December 2007

From field data, outcrop observations, and ground-water flow studies, this paper illustrates that if the assessment of the fracture network organization is effectively an important stage of the reservoir characterization, it cannot be dissociated from the evaluation of the scale relationships, the relation with stratigraphy, and the distribution of fracture hydraulic properties.

In Lacq Field, a giant gas field in a fractured carbonate reservoir, the flow network is assessed through the use of dynamic data. Vertical distribution of producing zones shows a very clear control of effective open fractures by stratigraphy, and therefore carbonate lithology.

In the same time, producing zones are not located in the areas in which fracture density is the highest. Same results are obtained from the observations of in-situ fracture networks and water incomes in a tunnel and a subsurface quarry. It clearly demonstrates that fracture density is the not the driving parameter for flows, and could be anti-correlated with fracture effective aperture.

The computation of equivalent permeability on fracture models shows that fracture aperture distribution (and therefore hydraulic properties distribution) is a more prevalent parameter for uncertainty assessment than fracture distribution.

Lastly, the spacing between open producing fractures along vertical or horizontal profiles show either exponential or power-law experimental distributions, regarding the spatial correlation between geological features. This proves the hierarchical organization of the flows, together with the needs for an evolution of the simplistic representation of a constant matrix block size within each cell of the dual porosity reservoir model.

These studies enable to up-date the typology of fractured reservoirs we previously published
Mechanistic and Simplified Models for Oil-Water Countercurrent Flow in Deviated and Multilateral Wells
Authors: Ouyang Liang-Biao
Published: December 2007

Water circulation and oil-water countercurrent flow in a deviated or multilateral well has been investigated in the present paper. Flow patterns for the countercurrent flow have been identified. Two practical criteria for determining the occurrence of countercurrent flow in deviated wells are introduced. Five categories of flow patterns for the countercurrent flow in pipes or wells are identified. Transitions among different flow patterns are proposed. Both a mechanistic model and a simplified model are developed for describing the oil-water countercurrent flow in deviated and multilateral wells. Solution procedure for using the newly-developed models is discussed.
Evaluation of Fiscal Terms, Reporting Reserves, and Financials
Authors: Young E. D. , McMichael C. L.
Published: December 2007

This paper examines the wide variety of international agreements that are currently used by host governments when granting rights to explore for, develop, produce and market hydrocarbons. The variation in fiscal terms found in these agreements covers a broad spectrum. In addition, their structures are often very complex making comparison of alternative project opportunities difficult. The key differences in the agreements and approaches that are commonly used to compare different fiscal regimes are discussed in detail. A case example with sensitivity analysis is used to illustrate the techniques used to model and perform economic evaluations of specific agreement types and terms. Commonly used definitions and accepted practice for the determination and classification of hydrocarbon volumes are presented. Host and home government regulations that govern and establish the criteria for external reporting of reserves and related financial information are also discussed in contrast with internal reporting needs for technical and business planning purposes.
Improving Production Results in Monobore, Deepwater and Extended Reach Wells
Authors: Almond Ken , Coull Craig , Knowles Peter , Smith James , Smith Michael V. , Mowbraw Kyle
Published: December 2007

Big bore completions (i.e., those using 6-5/8-in. and larger production tubulars) are required for economical production and injection in prolific reservoirs. A variety of completion configurations exist, though only the most traditional schemes have been discussed.

This paper will present the results of a study that analyzed and evaluated more than 350 large bore completions over a 20-year span to determine best practices. The study formed the basis for a new approach to well design that merges wellbore construction with the completion. The paper will discuss this approach, which includes a classification system to help operators choose the optimum design to match their completion objective.

This paper will begin by reviewing the big monobore concept, discuss various enabling technologies and their opportunity to increase production while reducing costs, review configuration choices with case histories and conclude with a case history that illustrates how the big monobore concept is evolving in the world's largest gas field.
A Case History on the Use of Down-Hole Sensors in a Field Producing from Long Horizontal/Multilateral Wells
Authors: Clancy Thomas F. , Balcacer Jairo , Scalabre Sebastian , Brown George , O’Shaughnessy Paul , Tirado Ricardo , Davie Greg
Published: December 2007

All of the production wells in this field were drilled and completed as horizontal and multi-lateral wells. The well designs range from a single lateral in a single sand body to where the upper and lower horizontal laterals intersect several sand lenses. The oil, an extra-heavy (9 API), high viscosity oil, requires a completion using artificial lift due to the low reservoir pressure, which will not support a column of water.

The use of down-hole pressure and temperature sensors with Surface Read-Out (SRO) was an integral part of the original well completions on production wells to monitor the individual well and pump performance. Vertical monitoring wells, drilled and completed through the multiple sand lenses present, expanded the use of down-hole sensors as data was sought on the area extent and pressure drawdown in the various sands being produced.

Efforts to determine the contribution to flow and the pressure losses encountered in horizontal wells led to the use of multiple sensors installed at depths along the long horizontal lateral. A change to the drilling of complex multi-lateral wells resulted in the use of tandem sensors to determine the relative contribution to flow from the lower and the upper lateral(s). All of these approaches, combined with the inability to use conventional Production Logging Tool techniques, led to the application of new technology combining fibre optics with multiple sensors to obtain a real time alternative to a PLT. As many as 15 surface read-out sensors were successfully installed in 7000 feet long horizontal well sections with measured depths up to 10,000 feet.
Real-Time Monitoring and Control of Water Influx to a Horizontal Well Using Advanced Completion Equipped with Permanent Sensors
Authors: Bryant I. D. , Chen M. -Y. , Raghuraman B. , Schroeder R. , Supp M. , Navarro J. , Raw I. , Smith J. , Scaggs M.
Published: December 2007

We have tested new technologies for real-time monitoring and control of water influx to horizontal wells with sand control completions. We drilled a horizontal well in a thin oil column in Indiana, which was completed openhole with sand screens and a gravel pack. External casing packers subdivide the annulus into three zones. An electrical valve, which also records the annular and tubing pressure, controls inflow to each zone. Twenty-one centralizers act as electrodes to form a resistivity array that spans the 694-ft-long completion. The well is also equipped with a fiber-optic-distributed temperature sensing system. The well has been produced since November 2001 and provides real-time data that are shared across a geographically distributed network and used to optimize the production of oil from the well.

The data from the pressure sensors and the resistivity array have been jointly interpreted to dynamically update the static reservoir model, which was initially based on observations in offset vertical wells. The pressures recorded from the three electrical valves provide high-frequency data to characterize the near-well heterogeneity of the formation. This is critical to computing an optimum production strategy. Zonal well tests, combined with interference testing between zones and wells, allow for estimation of communication between zones and the productivity index of each zone. The resistivity data enable detection of water saturation changes both in the formation and in the wellbore.

The completion technology tested in this well offers the potential to intelligently operate long horizontal sand control completions by combining real-time monitoring with downhole inflow control.
Real-Time 3D Earth Model Updating While Drilling a Horizontal Well
Authors: Malinverno Alberto , Andrews Ballard , Bennett Nicholas , Bryant Ian , Prange Michael , Savundararaj Philip , Bornemann Ted , Raw Ian , Britton David , Peters J. Gary
Published: December 2007

We describe here a test of a new technology for successful drilling of horizontal wells in thin oil columns. We constructed a three-dimensional (3D) earth model of the overburden and of the target reservoir layers on the basis of predrilling data and updated this model in real time on the basis of logging-while-drilling (LWD) measurements transferred to remote locations using the World Wide Web. This strategy allowed us to check and update the planned drilling trajectory continuously with all the information available at any given time.

We used uncertainties in the depth of markers observed in a number of offset vertical wells to determine the uncertainty in the thickness of layers in the earth model. This 3D model comprised best estimates of the thicknesses and a covariance matrix that quantified their initial uncertainties. We then drilled a pilot well. Trajectory data, LWD logs, and resistivity images from downhole measurement-while-drilling (MWD) and LWD tools were transmitted in real time from the Simpson No. 22 drill site in Indiana to a prototype application running in Connecticut. As we acquired new measurements in the pilot well, we compared log curves predicted by the model to the measured logs. Our prototype allowed an interpreter to update the location of markers as the well was drilled; an update of the entire 3D earth model and its uncertainty was then automatically computed in near-real time. Quantified uncertainties are key in this stage to ensure that the model update is in agreement with all the data considered previously. This procedure was repeated while drilling the horizontal drain hole, which was successfully steered within a dipping 6-ft-thick layer for 808 ft.

Our prototype also allowed for remote collaboration: 3D model updates, LWD data, and resistivity images were available to collaborators who were connected to the network and simultaneously ran copies of the prototype at additional locations. In particular, the remote availability of real-time resistivity images was key to the successful well placement, as these images show how the well trajectory follows the layering. Remote collaboration means that drilling decisions can be made collaboratively by a globally distributed team in a secure network environment. This can be a key capability for geosteering, especially in remote locations or when staffing is constrained.
Study of Gas-Condensate Well Productivity in Santa Barbara Field, Venezuela, by Well Test Analysis
Authors: Briones Mario , Zambrano Judith A. , Zerpa César
Published: December 2007

Numerous gas condensate well production data have shown that well productivity is severely affected when the bottom hole flowing pressure drops below the fluid dew point pressure. This productivity reduction is caused by liquid accumulation around the well. It is essential to take account of this ‘condensate blockage’ effect when calculating well productivity since productivity losses can be significant.

Published laboratory, simulation and well-test data have shown that at bottom hole flowing pressure below the dewpoint pressure three regions are created with different liquid saturation.

Since the retrograde condensation has an important impact on gas condensate well productivity, the optimum exploitation of these reservoirs depends on the ability to diagnose condensate bank. Well test data has proven to be one of the few reliable field data of practical use to detect the existence of retrograde condensation. In Santa Barbara field, the biggest Venezuelan gas-condensate field, application of the latest practical well-test analysis methods contributed to demonstrate the presence of velocity stripping and retrograde condensation despite conventional reservoir engineering analysis did not show such phenomena.

The paper discusses how the use of two and three radial composite model helped to gain a better understanding of Santa Barbara condensate reservoir behaviour when 1999 to 2001 well tests were reinterpreted. As velocity stripping was detected, near well bore relative permeability measurements were proposed in order to take account of the phenomena which occur at high flow rates when calculating well productivity in the field-scale simulation model.
Relative Permeability from Capillary Pressure
Authors: Papatzacos Paul , Skjæveland Svein M.
Published: December 2007

A new theory is reviewed for single-component, two-phase flow in porous media. It includes wettability and capillary pressure as integral parts of the thermodynamic description and does not make use of the relative permeability concept. However, by providing a capillary pressure correlation, we are able to extract relative permeabilities and to show good consistency between rock property correlations.
Wettability Effect on Oil Relative Permeability During a Gravity Drainage
Authors: Pedrera B. , Bertin H. , Hamon G. , Augustin A.
Published: December 2007

Gravity assisted gas displacement of oil in reservoirs is increasingly being considered. Accurate estimates of relative permeabilities are needed to understand and predict fluids motion, especially when very low oil saturations are reached.

The present work aims at conducting gravity drainage experiments in laboratory conditions. It particularly outlines wettability effect on recovery and relative permeabilities. The study is divided in two parts. In the first one, gravity drainage experiments under secondary conditions are performed with different core wettabilities. In the second one, relative permeabilities are determined from the experimental data using a semi-analytical calculation and an identification method based on a numerical model.

The experiments are performed on long (one meter) artificial consolidated porous media. Average porosity is 40% and absolute permeability to brine is around 6 Darcy. Fluids are air, refined oil of moderate viscosity and a brine. Wettability is modified by an ageing technique using a crude oil in place of the refined oil and keeping the core in an oven at controlled temperature and time. This process provides reproducible conditions of wettability estimated using the Amott test. During gravity drainage, oil recovery is recorded (weighting machine) and saturation profiles are measured using a gamma ray attenuation technique.

The oil relative permeabilities are determined through an analytical treatment of the multiphase displacement model, where capillary pressure is known. They are directly calculated from the different saturation profiles measured along the core and then expressed in a Corey's form. In addition, experimental observations are matched as closely as possible by numerical simulations.

The results are presented in terms of oil recovery and relative permeability. Oil recovery depends on wettability: a larger production time is observed for oil-wet media compared to the water-wet core and final oil recovery increases when the core is being oil-wet. The wettability effect on relative permeability is less obvious: it is strong between the water-wet case and the other situations, but weaker when considering the intermediate media.
Laboratory Measurements of Condensate Blocking and Treatment for Both Low and High Permeability Rocks
Authors: Al-Anazi Hamoud A. , Pope Gary A. , Sharma Mukul M. , Metcalfe Robert S.
Published: December 2007

Coreflood experiments were conducted in Berea sandstone and Texas Cream limestone cores to quantify the loss in relative permeability caused by condensate accumulation. The in-situ condensate saturation was established dynamically by precise control of core inlet and outlet pressures. It is well known that retrograde condensate dropout can cause significant productivity loss in low permeability reservoirs. This paper shows that such losses can also occur in high permeability reservoirs. Gas relative permeability reductions of 91% to 97% were seen in 2-5 md limestone cores and 95% to 98% in 246-378 md sandstone cores. In light of the new data presented here, the common perception that condensate blocking around wells in high-permeability reservoirs is not significant should be re-examined. Our previous coreflood experiments showed that methanol treatments increased the gas relative permeability in low permeability carbonates, but we had not yet determined the required methanol treatment volumes as done in this study. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period. Methanol also displaces water and this can also contribute to higher gas relative permeability in those cases when the initial water saturation is high enough to significantly add to the total liquid blocking of the gas. These results can be used to help reservoir engineers evaluate and treat gas-condensate wells with reduced productivity. Reservoir engineers should be especially careful to evaluate the damage done in such high-permeability reservoirs if the well's pressure drawdown is high enough to result in pressures below the dew point pressure.
A New Technique to Troubleshoot Gas Hydrates Buildup Problems in Subsea Christmas-Trees
Authors: Marques L. C. C. , Pedroso C. A. , Neumann L. F.
Published: December 2007

The paper is aimed at describing the series of actions taken to re-entry a well whose (wet) Christmas-tree-cap was clogged by hydrate buildup and therefore could not be released by means of a regular releasing tool. A deepwater well located in Campos Basin, offshore Rio de Janeiro, Brazil, was the scenario for this unique job. To our best understanding the kind of approach used to solve this hydrate problem has never used by industry before.

A patented thermochemical method – the so-called self-generated nitrogen (SGN) method–was applied to heat and dissociate the crystallized hydrate, which was clogging the tree-cap-locking-pin's piston chamber. Heat application around the body of the Christmas tree enabled us to dissociate the hydrate and release the tree cap by means of its regular retrieving tool.

This paper describes all the steps taken to perform this pioneer workover job. As a matter of fact, a multidisciplinary task that encompassed the following points: - development of a "tailor-made" environmental-friendly SGN formulation, - heat exchange simulations to design the optimum volume for the SGN treatment batch, - a review of the theoretical aspects of hydrate formation/dissociation, - mechanical modifications of the (regular) tree-cap releasing tool and, - a meticulous job and safe procedures review.
Challenges in Pigging of Subsea Gas Flowlines
Authors: Jayawardena Subash , Dykhno Leonid , Hudson John
Published: December 2007

Pigging is a common operation in the oil and gas industry. Pigging of flowlines is done with many objectives, including cleaning deposits such as wax layers, removal of liquids and flowline inspection. Pigging of gas flowlines in preparation for a restart of production after a flowline shut-in can provide challenges, as a significant amount of liquid may be left in the flowline. This liquid, when removed using a pig, accumulates upstream of the pig and moves towards the host facility during the operation.

This paper describes the challenges of gas flowline pigging. Gas flowline pigging initiated via a subsea pig launcher (in case of a single flowline) or from the host facility (in case of a dual or loop flowline) can be done using produced fluids. The major concerns are the subsea pig launching and control of pig movement, especially when pigging is done with produced gas. The factors affecting the dynamics of the pig and the produced fluids will be discussed. Special emphasis will be placed on discussing the challenges associated with the subsea pig launching required for single flowline pigging operations. The implications of these control challenges are also considered in light of pigging effectiveness.

Modeling experience of both single and dual (or loop) flowline configuration will be presented. The problems caused by hilly terrain as well as the steep risers leading to host platforms in deepwater subsea gas flowline systems will be discussed. Unless properly controlled, pigging of some gas flowlines results in unacceptably high pig velocities. Recommendations will be made on the optimization of subsea flowline pigging.
Energy Education: A Course for the 21st Century
Authors: Fanchi John R.
Published: December 2007

Energy demand is expected to grow this century as more countries seek a better quality of life for their citizens. The growth in energy demand will be met by a global energy mix that is undergoing a transition from an energy portfolio dominated by fossil fuels to an energy portfolio that includes a range of fuel types and energy conservation measures. This paper describes an Energy Engineering course for undergraduates that will increase the quality and quantity of engineering graduates as they embark on careers in the public sector and the emerging energy industry.
Project Valuation: Progressing from Certainty through Passive Uncertainty to Active Project Management
Authors: Chorn L. , Sharma A.
Published: December 2007

Investment opportunities with uncertain outcomes are the mainstay of the upstream energy industry. Valuation of these opportunities focus on the "invest / don't invest" decision. Companies have developed standard techniques to valuation to support this decision, but as more sophisticated techniques become available, managers and analysts stretch the standard to add more realism to the valuation.

This article presents a systematic study of valuation techniques. It begins with an investment problem, described by the expected value of key economic variables, which is properly valued by traditional discounted cash flow (Stage One). When the stochastic nature of key economic variables is included, it becomes necessary to increase the complexity of the analysis (Stage Two). The valuation evolves to a decision tree analysis, using a discrete representation of the distribution of NPV outcomes. As more granularity is included in the stochastic variable descriptions, Monte Carlo simulation is used to compute a continuous probabilistic NPV of the opportunity. Through stage two, the valuation process assumes management is passive in its ability to resolve the uncertainty in key economic variables. When an investment opportunity offers management the ability to resolve uncertainty before making an irreversible decision and management of the investment program is possible, the valuation process requires Real Options analyses techniques (Stage Three). As with Stage Two valuations, Real Options has discrete and continuous solution techniques for the valuation equation.

We compare the valuation provided by three techniques for the acquisition of a portfolio of maturing oil and gas properties. Through this systematic approach, the study provides a perspective for matching an investment opportunity with the appropriate analysis technique, based on the characteristics of the opportunity.
An Intelligent Identification Method of Fuzzy Models and its Applications to Inversion of NMR Logging Data
Authors: Finol Jose , Romero Carlos , Romero Pedro
Published: December 2007

In this paper we describe a novel approach to fuzzy model identification that gives solution to the inverse problem of permeability prediction from NMR data. The fuzzy logic approach uses fuzzy If-Then rules to establish the relationship between permeability (output variable) and the NMR T2 distribution mean values ϕNMR, ϕFF, ϕBF (input variables). We introduce an intelligent data-driven method that generates the fuzzy rules in a two-steps learning algorithm. In the first step, fuzzy clustering is performed on a set of input-output core measurements to obtain an initial approximation of the fuzzy rules in a rapid prototyping approach. This set of observations is the only information assumed about the model behavior. In the second step, the antecedent and consequent parameters of the identified fuzzy rules are fine-tuned by means of a gradient descent method. The identified fuzzy model is subsequently used to estimate permeability in uncored wells in the same field.

Computer simulations using data from a complex siliclastic sequence in the Maracaibo Basin (western Venezuela) show the advantages of this methodology over the conventional empirical and statistical inversion methods.
Why We Should Stop Using Pseudopressures and Other Good Old Well Test Interpretation Tools After So Many Years of Good Service
Authors: Houzé Olivier P.
Published: December 2007

Some well test interpretation techniques still in use today were developed more than 30 years ago, to help the engineer at a time he/she (generally he) only had graph paper, a hand calculator and a set of printed type-curves. Unlike human beings, age is not a reason by itself to retire a technique. But, originally invented by paradigm breakers, thanks to our inertia some techniques have become paradigms themselves. They no longer bring anything, they confuse the learning of young engineers and worse, sometimes turn out to be incorrect and stand in the way of more rigorous and promising developments. It may be time to retire them from our industry, acknowledging what they brought us in the past. The author respectfully suggests to get rid of type-curves, pseudopressures1 and pseudotimes2. In each case, the author will try to explain why these tools were developed, why they were originally useful, but no longer. If the author survives this one, the following publication will deal with the Horner3 plot, equivalent time functions4 and deconvolution5. Otherwise there is absolutely nothing new in this paper.
Numerical Sensitivity Studies for the Joint Inversion of Pressure and DC Resistivity Measurements Acquired with In-Situ Permanent Sensors
Authors: Alpak F. O. , Torres-Verdín C. , Sepehrnoori K. , Fang S.
Published: December 2007

In-situ permanent sensors allow the possibility of monitoring in real time dynamic changes in formation properties due to primary or enhanced hydrocarbon recovery. A feedback loop can be enforced in response to in-situ permanent sensor data to optimally control the recovery of hydrocarbon assets. Prototypes of in-situ permanent sensors include pressure gauges, acoustic geophones, and direct-current (DC) resistivity electrodes.

In the past, quantitative studies have been performed to assess the value of in-situ permanent pressure data to mapping permeability variations in close proximity to the sensor deployment1. Malinverno and Torres-Verdín2 on the other hand, have described a procedure to estimate water invasion profiles using in-situ DC resistivity sensors. However, to date little is known about the possibility of estimating petrophysical variables that jointly honor pressure and DC resistivity data acquired with in-situ permanent sensors. The two types of data sense different and complementary components of the underlying petrophysical model, and it seems appropriate to develop a quantitative estimation procedure that can assimilate the best elements of the two types of measurements. In this paper, we develop a methodology to jointly invert pressure and DC resistivity data acquired with in-situ permanent sensors in a hypothetical water injection experiment. Time-variable flow rates are enforced while injecting water into the surrounding rock formations, hence producing a sequence of repeated pressure pulses. The objective of the experiment is to estimate permeabilities, porosities, and fluid distributions that honor (a) sensor data acquired during a single pressure pulse, and (b) a more complete time record of pressure data acquired starting from the early stages of water injection. Our inversion results shed new light to the independent and joint sensitivity of noisy pressure and DC resistivity data to detecting dynamic perturbations of petrophysical properties. Examples of inversion are used to assess the relative benefits of different types of sensor deployments.
Downhole Fiber-Optic Multiphase Flowmeter: Design, Operating Principle, and Testing
Authors: Kragas Tor K. , Bostick F. X. , Mayeu Christopher , Gysling Daniel L. , van der Spek Alex
Published: December 2007

Real-time, downhole, multiphase flow rate data is widely acknowledged to be of significant value for production optimization. This is particularly the case for high-cost deepwater developments and in complex multi-lateral wells. Applications of downhole flow data include zonal production allocation, identifying and localizing production anomalies, direct determination of well productivity index, ability to commingle production from multiple zones, and reduction in surface well testing and facilities requirements. However, despite the potential value of this data, in the past reliable continuous measurements of downhole flow rates in producing wells have not generally been available because of difficulties in designing and deploying measurement devices for hostile in-well environments.

This paper discusses the design, operating principles, and flow loop testing of the world's first all-fiber optic multiphase flowmeter for downhole deployment. The flowmeter provides real-time measurement of flow rate, phase fraction, pressure and temperature. It is deployed with the production tubing and is rated to 125°C and 15,000 psi. It is full-bore, non-intrusive, has no moving parts, is electrically passive, and overcomes the design limitations imposed by downhole environments. Thus, it has the potential for providing highly reliable downhole measurements. The flowmeter has been extensively tested in Shell's multiphase flow loop in Rijswijk, The Netherlands over a wide range of oil and brine compositions and phase fractions, flow rates, and meter inclinations. Results from the testing have demonstrated the ability of the flowmeter to measure flow rates and water fractions in oil-water systems to within ±5% over the entire range of water cuts. These results have been validated by data from several field deployments.
Optimization of Production Operations in Petroleum Fields
Authors: Wang Pengju , Litvak Michael , Aziz Khalid
Published: December 2007

For some petroleum fields, optimization of production operations can be a major factor for increasing production rates and reducing production costs. While for single wells or other small systems simple nodal analysis can be adequate, large complex systems demand a much more sophisticated approach. Many mature fields are produced by gas-lift under multiple constraints imposed by the field handling capacity of the system. In this paper we present an optimization technique for allocating production rates and lift-gas rates to wells of large fields subject to multiple flow rate and pressure constraints.

The well rate and lift-gas rate allocation problem has been addressed in the literature1-13. However, existing methods are either inefficient or make significant simplifications. This often leads to suboptimal operations. This paper proposes a new formulation of the problem that is able to handle flow interactions among wells and can be applied to a variety of problems of varying complexities. We show that the proper formulation of the optimization problem is important in the practical use of modern optimization techniques. Once formulated, the optimization problem is solved by a sequential quadratic programming algorithm. Our results show that the procedure developed in this paper is capable of handling complex oil production problems.