bluuebunny/crossref_metadata_2025 huggingface dataset:
A Case History: The Installation of a Damaged Control Line Replacement Safety Valve System in a North Sea Well
Authors: Barratt T. , Goldsworthy B. , Hamilton S. , Lacy R. , Taylor M. , Ross A. , Mackie S. , Calzoncinth E. , Dennistoun S. , Jacob J.-L.
Published: February 2011

The GA-03 well on the Gannet platform in the UK sector of the North Sea developed a blockage in the safety valve control line that rendered the existing tubing retrievable safety inoperable. In addition, the seal bores inside the valve were scarred and damaged badly enough that a conventional wireline safety valve would not seal. These were the problems confronting the operator as they planned remediation work to return the well to production. Initially a major rig workover had been anticipated to pull the tubing and replace the safety valve and control line. This operation required the use of a Hydraulic Workover Unit (HWU) to perform the work which would carry a multimillion dollar cost.

An alternative method was examined that would allow replacement of the safety valve and control line without pulling the production tubing or making changes to the wellhead configuration. This alternative method was a new concept not previously attempted by any operator in the North Sea. This innovative approach would involve the installation four elements:

A new safety valve landing nipple in the production tubing using a specially modified seal bore production packer. A new wireline safety valve that would be landed in the new landing nipple A new control line and special control line connector installed inside the production tubing. A modified lower master valve to allow wellhead penetration for the injection of hydraulic power fluid to the new control line.

This particular combination of tools had never been run together and their installation would have to be accomplished under a severe deadline, as the HWU job had been planned for execution in September 2009. To accomplish this, the entire operation had to be planned, designed, manufactured, tested, qualified and installed in the GA-03 well before the end of the year. It is a great credit to the project team that from initial proposal for use of the new system in July, they were able to achieve the target date of returning the well to production by the end of 2009. This showed the high level of cooperation and collaboration between the operator and the completion tool and wellhead providers.

This paper will describe in detail the system components and the decision processes and evaluations that led to the selection of this alternative repair method. The collaborative efforts between the operator and two major service providers will be examined and discussed and the installation procedure described in detail. The paper will describe why the successful completion of this project marks a significant milestone in the remediation of older producing wells.
Designing, Implementing, and Sustaining a Business-Driven Competency and Employee Development Program
Authors: Demski Dave , Leuro Jorge
Published: February 2011

Employees, through their competence and commitment, are responsible for a large measure of business success in the oil and gas industry. This paper describes how Halliburton designed, implemented, and is continuing to sustain a global program to develop more than 40,000 of its workforce of 54,000. The company has created a unique employee development program that links work processes, business performance, employee training, competency development, and employee engagement. This case history demonstrates the effect that developing employees can have on business results.

The program has been implemented globally for 10 product service lines and eight support groups in eight regions; it provides a standard and a business-focused means of developing employees. A structured implementation process was used to ensure that the program was business-driven and that there was clear accountability for its implementation.

Effective development and engagement of employees improves business performance in the areas of service quality; health, safety, and environment; employee retention; and financial results.

Since the inception of the program, it has provided the following:

Reliable and business focused employee development framework Proven implementation process and accountability of all parties involved Improved business results by developing and engaging employees "Win-win" outcome for the company and for its employees
Treating Produced Water on Deepwater Platforms: Developing Effective Practices Based Upon Lessons Learned
Authors: Walsh John M. , Frankiewicz Ted C.
Published: February 2011

Deepwater platforms in the Gulf of Mexico and elsewhere are transitioning from dry oil or low water cut production to higher water cut production. These platforms face unique challenges resulting from water and crude incompatibilities, high salinity, no advance characterization of the water treatment issues, and a lack of space for water treatment equipment. The lessons learned by deepwater operators can provide an experience base upon which future operators can draw to assist them with projects to debottleneck and/or improve produced water treatment on their deepwater platforms and FPSOs.

Equipment and practices which have worked well and not worked well for treating produced water on floating platforms are described and the issues pertinent to the deepwater operation of this equipment are identified. The impact of the deepwater operating environment on produced water treatment systems is discussed. Platform motion, high shear across control valves or pumps, production from multiple reservoirs, process recycle streams, and the use of hydrate inhibitors or other chemicals all impact the design of a water treatment process and the operation of water treating equipment. The experiences detailed in this paper are intended to help engineers avoid the process design and equipment selection issues which were problematic for earlier deepwater operations.
Pore-Scale Simulation of Hysteresis Effects During Repressurisation of Gas-Oil Systems
Authors: Bondino I. , McDougall S. R. , Ezeuko C. C. , Hamon G.
Published: February 2011

Repressurisation of a hydrocarbon reservoir may occur either as a natural response to subsurface phenomena (for example, aquifer encroachment or fault re-activation) or as a consequence of a particular production strategy. In this paper we examine, for the first time to our knowledge, the pore scale mechanisms underlying the repressurisation of a gas-oil reservoir that has previously been exploited by solution gas drive. Our investigation, triggered by experimental observations in both glass micromodels and cores, utilizes a pore-scale network model: a modelling approach that is nowadays sufficiently mature to facilitate virtual experiments that are rapid, cheap and physically realistic.

The new physics implemented here captures a wide range of phenomena related to multiphase repressurisation, including gas re-dissolution in oil by diffusion, bubble retraction, fragmentation and re-stabilisation under gravitational forces, and oil reimbibition.

It is found that repressurisation is not simply the reverse of primary depletion, as the previously developed gas phase does not simply retract from the latest pores invaded during depressurization: rather, the process exhibits a large degree of hysteresis in both local supersaturation and gas phase distribution. We have studied the effects of several combinations of depressurization and repressurisation rates upon phase distribution and recovery, as the system is first depleted below bubble point and subsequently repressurised back to the starting pressure. Crucially, we find that a highly dispersed gas phase can persist once the original bubble point of the oil has been reached at the end of repressurisation. It is clearly shown that the repressurisation of an unequilibrated system essentially generates a high bubble density: this could theoretically be exploited by a secondary depletion to obtain improved recovery, as it is well known that the generation of large numbers of bubbles (generated by nucleation or, as we suggest here, induced by repressurisation) is highly beneficial for solution gas drive performance.
Getting Smarter and Hotter With ESPs for SAGD
Authors: Noonan S. G. , Dowling M. , D'Ambrosio L. , Klaczek W.
Published: February 2011

This paper summarizes the results from a high-temperature test program completed in late 2009 and discusses a new electric submersible pumping (ESP) configuration that was validated by ConocoPhillips for operations at 250°C and planned for 2010 field trials. This new prototype ESP system was jointly tested by ConocoPhillips and Schlumberger for 42 days in the C-FER Technologies high-temperature flow loop at fluid temperatures ranging from 150°C to 260°C, and at 250°C and above for approximately 40% of the total time.

While the primary objective of this test program was to validate this ESP system for use in 250°C fluid temperatures, the additional instrumentation at the test facility also offered an opportunity to investigate the temperature dynamics of the fluid flowing past the motor, and the pressure and temperature behavior of the motor. The test data was also compared to data from a similar test completed in 2008 and the evaluation provided some interesting observations, which will be discussed.

The information in this paper will be of value to any operator that has ESPs installed in high-temperature applications. In addition, the lessons learned from this test program may also be used to increase ESP reliability in conventional applications.
Using Burst Collars in a Liner String for Multi-zone Completions in Horizontal Wellbores: Case Study
Authors: Schoenfeld Jason , Kostenuk Natasha , Jorgensen Max , Sherman Scott
Published: February 2011

This paper introduces a new multi-zone completion technology (MZCT) to stimulate multiple stages in a horizontal wellbore that is either cased using external packers or cemented into place. In both scenarios, a liner assembly containing specialized collars with predrilled ports that are covered by burst disks is run into the horizontal section of a wellbore. There are no restrictions on the number of collars that can be run, nor the spacing between them. After the assembly is set, coiled tubing is used to complete each interval using a cup/cup assembly that straddles each specialized collar, and then pressures up to open the burst ports. The fracture is then initiated through the coil string into the reservoir, with the coiled tubing moving along the horizontal wellbore from the toe to the heel, the process being repeating against each specialized collar.

Advantages of this new system include no limits to the number of stages that can be completed, full bore diameter available following the stimulations without the cost of milling out mechanical ports, and the ability to do re-completions on the same intervals at a later date. The liner with the burst collars can be used with packers or cemented in, additional collars can be run and stimulated at a later date, and the completion is more cost effective than current alternatives.

This paper discusses the application of the cemented burst collars on the Viking formation in the Redwater field of Alberta and Plato field of SW Saskatchewan. Comparisons are made between the burst collar system and previous completion systems used in the Viking. Recognized benefits include reduced downtime during operations after a screen-out and tighter spacing between fracs in a cemented liner application as opposed to perforating.
Practical use of well test deconvolution
Authors: Gringarten A. C.
Published: February 2011

Deconvolution transforms variable rate pressure data into a constant rate initial drawdown with a duration equal to the total duration of the test. It yields directly the corresponding pressure derivative, normalized to a unit rate. It is not a new interpretation method, but a new tool to process pressure and rate data in order to obtain more pressure data to interpret with conventional techniques.

Although deconvolution has received much attention since 2001 following the publication of a stable algorithm by von Schroeter, Hollaender, and Gringarten, its use by practicing engineers is still limited. One reason is limited access to the algorithm, which had only recently become available in commercial well test analysis software products. The other is concerns on how deconvolution should be used and how reliable it is. As a result, few examples of practical applications of well test deconvolution are available in the literature.

This paper illustrates various uses of deconvolution in tests of short and long durations. Examples include DST's with erroneous rates, which deconvolution is able to correct; and data from permanent downhole pressure gauges in vertical and horizontal wells, where deconvolution shows compartmentalization and recharge from other layers, which could not be seen in the original data.

Recommendations on how to perform deconvolution and how to verify deconvolution results are also provided. It is hoped that this paper will encourage well test interpreters to use deconvolution confidently as part of the well test analysis process.
Conditioning Multilayered Geologic Models to Well-Test and Production-Logging Data Using the Ensemble Kalman Filter
Authors: Coutinho Emilio J. , Emerick Alexandre A. , Li Gaoming , Reynolds A. C.
Published: February 2011

Reservoir models utilize highly heterogenous permeability and porosity fields embedded in a structural model derived from geophysical and geological data. It is not uncommon for permeabilities in the initial model derived from static data to differ significantly from values obtained from the interpretation of well-test data. This paper presents the application of the ensemble Kalman Filter (EnKF) to assimilate pressure transient and production-logging data to update permeabilities, estimate layer skin factors and "effective" well skin factor in multilayered reservoir models. The methodology is applied to two synthetic cases and a field case. For the field case application, we consider two approaches. In the first approach we simply use multipliers to adjust the heterogeneous permeability field in each layer. In the second approach, we adjust the prior mean of each layer log-permeability field together with individual gridblock log-permeabilities.
An Innovative Approach to Optimizing Design of HP/HT Well Tubular Strings
Authors: Deng Guijun , Shyu Goang-Ding
Published: February 2011

In traditional well completion design, the size and geometric configuration of various structural tubular components are determined by a set of stress limits based on the material properties and type of loading under the worst conditions expected during the projected service life. Uncertainties associated with design variables are presumably compensated by introducing safety factors derived primarily from past experience. It is intuitively obvious that a lower safety factor leads to a design with higher risk. However, those safety factors give no quantitative indication of risk assessment of an intended design, and no insight into the degree of risk. Moreover, this approach often leads to over-conservative design and therefore excessive cost, or over-risk design, which can cause failure in tubular components.

This paper introduces an innovative approach to fill this gap. This approach integrates design of experiments (DOE) and stochastic study into the design process. It explicitly considers the variability and uncertainty of each design variable in probabilistic terms, and allows the assessment of probability of failure of the design; thus it is able to help achieve better designs and higher-reliability completion tools. Design of experiments provides an efficient methodology to study the effects of design changes and identify the most influential design variables, and, therefore, provides clear design performance improvement direction for complicated designs. Stochastic study addresses sensitivity of stress or strain limits, which are tied to the life cycle of the tools, under the influence of variability of design parameters, and provides quantitative estimation of probability of success of the optimized design. A deepwater high-pressure/high temperature (HP/HT) tubular string design example will illustrate this new approach. The analysis results indicate this approach leads to a more robust design.
Real-Time Monitoring of Sand Control Completions
Authors: Earles Denise M. , Stoesz Carl W. , Amaral Anderson S. , Pearce Jeremy G. , DeJongh Hans A. , Rambow Frederick H.
Published: February 2011

Subsurface geomechanical stresses can cause formation faults, slippage, and compaction. These movements result in well failures, impacting production and resulting in significant expense and lost revenue. Traditional means for detecting such failures are limited and usually require interrupting production to re-enter the well, resulting in late detection of the problem and limited counteractive options.

A fiber optic support device has been developed to permanently monitor strain and temperature on sand screen products for gravel-pack and frac-pack applications. This technology, especially when paired with an optical wet connect, provides for long-term reservoir monitoring at the sand face, resulting in early detection of subsurface movements at a high resolution. With this information, operators can plan early mitigative actions, and monitor the results of these actions in real time.

This fiber support device provides a means of holding a helically wrapped optic fiber rigidly in place at the sand face, with no negative impact on the sand control functionality of the sand screens. New techniques were developed to manufacture this technology, as well as a new method to install the fiber. Dry connects have also been developed to allow connections between individual sand screens and enable longer monitored intervals.

The paper will describe this new technology, review test results to date, and discuss potential applications.
3D Visualization and Classification of Pore Structure and Pore Filling in Gas Shales
Authors: Sisk Carl , Diaz Elizabeth , Walls Joel , Grader Avrami , Suhrer Michael
Published: February 2011

Shale gas is a growing resource worldwide as many basins are being explored and produced. However, little is still known and understood about two key parameters in gas shales: the gas-filled porosity and permeability. Digital rock physics technique, presented in this paper, contains three basic steps: (a) 3D CT imaging at 200 nanometer resolution, and/or FIB-SEM (focused ion beam combined with SEM) imaging at 3-15 nanometer resolution (b) segmentation of the digital volume to quantitatively identify the components, including the mineral phases, organic-filled pores, and free-gas inclusions; and (c) computations of TOC (Total Organic Content), porosity, pore connectivity, and permeability in three axis.

A number of gas shale samples have been used, to specifically analyze the pore systems. The characteristics including dual porosity, organics distribution, gas-filled porosity distribution, and how these properties relate to the maturity of the organic material. Pore geometries (pores filled either with organics or free gas) of these samples fall into the following categories: (a) relatively large (up to 4 micron) with poorly disconnected pores; (b) pores connected by very thin (down to 15 nanometers) conduits; (c) dual porosity system where the large pores are interconnected by large conduits and very thin conduits are interconnected and also connected to the large pores. Within each of these three categories, the pore space may be (a) completely filled with organics or (b) partially or completely filled with gas.

The latter is of most interest as it is a gas source. In such systems we observe various geometries of pore space, including (a) disconnected pores floating in the organics and (b) connected pores within the organics. TOC, open pore volumes, as well as pore-space connectivity are not just qualitatively estimated from the images but quantitatively computed for a given sample. Our ongoing effort is to relate the quantitative patterns thus computed to the maturity of shale.
Carbon Dioxide Storage Capacity of Organic-rich Shales
Authors: Kang S. M. , Fathi E. , Ambrose R. J. , Akkutlu I. Y. , Sigal R. F.
Published: February 2011

This paper presents an experimental study on the ability of Barnett shale core samples to store carbon dioxide. An apparatus has been built for psrecise measurements of gas pressure and volumes at constant temperature. A new analytical methodology is developed allowing interpretation of the pressure-volume data in terms of measurements in total porosity and Langmuir parameters of core plugs. The method considers pore volume compressibility and sorption effects and allows small gas leakage adjustments at high pressures. Total gas storage capacity for pure carbon dioxide is measured at supercritical conditions as a function of pore pressure under constant reservoir confining pressure. It is shown that, although widely-known as an impermeable sedimentary rock with low porosity, organic shale has the ability to store significant amounts of gas permanently due to trapping of the gas in adsorbed state within its finely-dispersed organic matter, i.e., kerogen. The latter is a nanoporous material with micropores (< 2 nm) and mesopores (2-50 nm). Storage in organic shale has the added advantages because the organic matter acts as molecular sieve allowing carbon dioxide —with linear molecular geometry— to reside in small pores that the other naturally-occurring gases cannot access. In addition, the molecular interaction energy between the organics and carbon dioxide molecules is different which leads to its enhanced adsorption. Hence, affinity of shale to carbon dioxide is due to partly steric and thermodynamic effects similar to those of coals that are being considered for enhanced coalbed methane recovery.

Mass transport paths and the mechanisms of gas uptake are unlike coals, however. Once at the fracture-matrix interface, the injected gas faces a geomechanically strong porous medium with dual (organic/inorganic) pore system, therefore, has choices of path for its flow and transport into the matrix: the gas molecules (i) dissolve into the organic material and diffuse through a nanopore-network, and (ii) enter the inorganic material and flow through a network of irregularly shaped voids. Although the gas could reach the organic pores deep in the shale formation following both paths, the application of the continua approximation to the percolation threshold is not known. Here, using gas permeation experiments and history-matching pressure pulse decay, we show that a large portion of the injected gas reaches the organic pores through the inorganic matrix. This is consistent with SEM images that do not show connectivity of the organic material on scales larger than tens of microns. It indicates an in-series coupling of the dual continua in shale. The inorganic matrix permeability is therefore predicted less, typically in the order of 10 nD. More importantly, transport in the organic pores is not due to flow but mainly pore and surface diffusion mechanisms.
Casing Drilling Application with Rotary Steerable and Triple Combo in New Deviated Wells in Cira Infantas Field
Authors: Lopez Edwin , Bonilla Pablo , Castilla Alfredo , Rincón Javier
Published: February 2011

La Cira Infantas (LCI) is the oldest Colombian field in production since the beginning of the twentieth century. Hundreds of wells are scattered throughout the field which is divided in two principal areas, La Cira and Infantas. This field is crossed by faults and is characterized by depleted and shallow gas bearing formations, challenging drilling activity with both loss circulation and well control issues.

Casing while drilling (CWD) has moved from being a new technology to one that is now recognized as a practical method of solving particular drilling problems, optimizing conventional drilling processes and consequently reducing drilling costs. This paper describes the process from the engineering and operational point of view of deploying CWD technology coupled with rotary steerable (RSS) and logging while drilling (LWD) tools, transmitting in real-time with electromagnetic (EM) telemetry in this mature field to improve drilling performance while taking advantage of the automated drilling rig already equipped to deal with casing and currently under contract in this field drilling wells conventionally.

Five injector wells were drilled. The wells ranged in depth from 3,400 to 4,600 ft MD. The project was completed successfully with all wells reaching the geological targets, setting the production casing at the desired depths and acquiring the data required by the Reservoir Team.

Lessons learned were applied from well to well which allowed the reduction of execution time from 7.06 drilling days on the first well to 3.54 drilling days on the last one, reducing the total well cost 28.1% from the first well to the last.
Diffusion in Naturally Fractured Reservoirs - A Review
Authors: Chordia Mudit , Japan J. Trivedi
Published: February 2011

The impetus for this work stemmed from the growing demand in the industry for Carbon Dioxide sequestration during incremental oil recovery and gas or solvent injection for heavy oil recovery from naturally fractured reservoirs. A thorough research and assimilation of available field data led us to believe that a better understanding of the diffusion coefficients and their impact on the overall recovery will go a long way in providing viable techniques in the Improved Oil Recovery sector. This knowledge will further enhance the understanding of the mass transfer process and mechanisms at a molecular scale in the reservoirs.

Remarkable amount of experimental and computational work has been carried out to study the effect of diffusion and dispersion mechanisms in naturally fractured reservoirs. However, what's missing is an extensive and critical review of the efforts in this direction. The synchronization of similar efforts and recognition of all the independent studies in a common direction would not only highlight the deficiencies and limitations of present scenario in the field, it will also give meaningful insight into further developments.

We have investigated methods employed by various authors to arrive at concurrent values for diffusion and dispersion coefficients. The main focus during our work was to, i) evaluate the role of diffusion and the factors that critically affect diffusion and oil recovery, ii) investigate current methods for calculation of the coefficients and iii) various methods/models to incorporate diffusion. Our work includes significant technological contributions and findings of experimental and simulation studies in the field to this day.

It is our understanding that our research will bridge the gap between the fundamental understanding and application of related processes and serve as a useful reference for engineers and researchers for present applications as well as the future.
Improved Production and Profitability Achieved with Superior Completions in Horizontal Wells: A Bakken/Three Forks Case History
Authors: Rankin R. , Thibodeau M. , Vincent M. C. , Palisch T. T.
Published: February 2011

The Bakken/Three Forks oil play is extremely active, with more than 2,500 horizontal wells drilled in Montana, North Dakota, and Saskatchewan during the past nine years. Typical well costs range between $4 -$8 million per well, suggesting the industry has invested more than $15 billion in this resource, in addition to lease, infrastructure, and operation expenses. Despite this enormous investment, the industry has struggled to identify best practices and many operators currently pursue significantly different strategies throughout the play.

This paper will summarize the development philosophy and key learnings of one operator in completing this low permeability reservoir with hydraulically fractured horizontal wells. Significant production gains have been achieved through advancements in completion methods, improving the overall economics of the Bakken/Three Forks oil play.

This paper describes the evolution of completion strategy, including:

– Lateral length and number of stages – Method of isolation – Completion and fracturing techniques – Proppant type and concentration

Through careful investigation and continual improvement, the authors have been able to significantly increase well production compared to their previous wells. Wells with improved completions have also experienced notably higher production rates than offset wells completed by operators with differing strategies. It is clear that lateral length and number of stages, coupled with proppant type and concentration, are key variables that have significantly improved well productivity and profitability. Included economic and financial analyses demonstrate that Bakken/Three Forks profitability can be dramatically improved by altering completion designs. Although specific treatment parameters should be adapted as formation characteristics vary across the play, it is believed this discussion of current design strategy will be useful to the SPE audience and accelerate optimization of Bakken/Three Forks completions. Future innovation will occur, and it is hoped that the publication of these learnings will encourage additional experimentation and optimization.
Safety Valve for Ultradeepwater Lower Tertiary Applications
Authors: Sloan Jim , Bane Darren
Published: February 2011

In recent years, offshore oil and gas exploration has continued to push into deeper and deeper waters, such as those in the Lower Tertiary fields of the Gulf of Mexico. As these field discoveries are being completed, the application requirements for safety valve installations are moving toward valves that can be set extremely deep, yet still require a relatively low operating pressure to control the valve. In traditional safety valve applications, operating pressures are sensitive to the wellbore pressure and are typically above those pressures to hold the valve in the open position. As the setting depth of these valves goes deeper, the operating pressures can increase to a significant level such that the design and performance of the umbilical and wellhead is detrimentally affected.

As a result of these constraints that occur in deep, offshore fields, a safety valve solution is desired to provide an ability to minimize opening pressures by balancing tubing pressure in HP/HT conditions, yet allow extreme valve setting depth capability without compromising operational characteristics such as high opening pressures or pressure- balanced pistons using long-term valve gas charge storage.

This paper discusses a new surface-controlled, subsurface safety valve (SCSSV) that employs the low opening pressures of a tubing-pressure-insensitive safety valve, without gas-charged assisted closure or dual control lines for balanced line applications. This system enhances valve reliability by eliminating the need for pressure reversals across the valve's critical actuating piston seals while maintaining tubing pressure insensitivity. This system provides for much deeper valve depth capabilities compared to the methods previously discussed and also allows the safety valve to account for annulus pressure buildup scenarios not possible in current SCSSV applications.

This paper presents design and development considerations for a new SCSSV solution allowing ultradeep setting depths without closed volume gas charged spring techniques utilized in current deep-set SCSSV technology. Test results will demonstrate the features, benefits, and reliability of this new safety valve in reference to previously unattainable valve operating depths in aggressive subsea well designs or annulus pressure buildup scenarios.
Enumerating Permeability, Surface Areas, and Residual Capillary Trapping of CO2 in 3D: Digital Analysis of CO2CRC Otway Project Core
Authors: Knackstedt Mark , Dance Tess , Kumar M. , Averdunk H. , Paterson L.
Published: February 2011

In geological storage of CO2 there are four main trapping mechanisms; structural, dissolution, mineral and residual trapping. While structural and dissolution trapping depend on the large scale structure of the reservoir, both residual and mineral trapping are strongly influenced by geometry at the pore scale. The dominant mechanism for residual capillary trapping is snap off which depends largely on the interconnectivity of the pore space and ratio of the pore throats to pore bodies. Mineral trapping depends largely on the surface area and mineralogy of the rock. Digital core analysis makes it possible to directly enumerate the detailed pore and mineral phase structure of core material in 3D. Flooding experiments enable the amount and microscopic distribution of residual fluid phases to be directly imaged in 3D. In this paper the pore scale properties associated with mineral and residual capillary trapping are directly enumerated using core material from the CO2CRC Otway CO2 storage project in Australia. Surface areas associated with varying mineral phases are quantified. 3D pore network characteristics are derived from the image data which allow the quantification of the pore network structure (e.g., interconnectivity) and the pore geometry (pore/throat size, pore shape, aspect ratio). Heterogeneity of the permeability and anisotropy are calculated directly. The amount of residual non-wetting phase of analog fluid pairs is directly measured on Otway core material after flooding at the pore scale in 3D. The microscopic distribution of the residual non-wetting phase within the pore space is quantified and individual pore occupancies defined. This information will provide a better understanding of recovery mechanisms and assist in the design and implementation of CO2 flooding processes. Comparison of individual pore occupancies based on 3D image data provides a foundation for quantitative comparison of experiment to pore scale modeling and enable testing and calibration of pore network predictions of CO2 storage.
Pressure Buildup Test Analysis of a Gas Condensate Well in the Middle East
Authors: Al Ismail Maytham I. , Horne Roland N.
Published: February 2011

The deliverability of rich gas wells producing below the dew-point pressure is severely impacted due to condensate banking around the wellbore. Condensate banking also complicates the pressure transient test analysis due to multiphase flow and mixture composition change. The three-zone method to compute the two-phase pseudopressure gives more accurate reservoir properties than the single-phase pseudopressure method, because it accounts for the composition change in the reservoir. The three flow regions are: inner region 1 where gas and condensate flow simultaneously, middle region 2 where gas and condensate are present but only gas is mobile and outer region 3 where only gas is present.

In this work, three pressure build-up tests for a Middle Eastern gas-condensate well were history matched with a compositional simulator. First, the PVT test results of the reservoir fluid were simulated using Peng-Robinson equation of state. Then, the generated fluid model was included in a radial compositional model that considered the three flow regions. The compositional model was used to history match the pressure build-up tests by modifying the reservoir properties. Then, the generated pressure buildup tests were analyzed using three pseudopressure techniques for comparison: the single-phase pseudopressure, the two-phase steady-state pseudopressure and the two-phase three-zone pseudopressure.

Results indicated that all three pseudopressure techniques were capable of estimating permeability accurately. However, variations in skin estimations were observed. The three-zone pseudopressure approach was able to consistently estimate skin accurately because it always represented the pressure-saturation relationship around the wellbore correctly. On the other hand, both the single-phase pseudopressure and the two-phase steady-state pseudopressure were unable to estimate skin accurately. The skin effect due to liquid dropout caused the skin factor estimations by the single-phase pseudopressure approach to be high. Additionally, the steady-state method overestimated the pressure-saturation relationship which ultimately caused the skin estimates to be low for the steady-state pseudopressure approach.
Liquid Entrainment in Annular Gas/Liquid Flow in Inclined Pipes
Authors: Magrini K. L. , Sarica C. , Al-Sarkhi A. , Zhang H.-Q.
Published: February 2011

Entrainment fraction is one of the key parameters in many applications including wellbore and flow line design, separator design, wellbore loading, corrosion inhibition, etc. This study provides the first comprehensive entrainment data and their critical analysis for a full range of inclination angles ranging from horizontal to vertical in 76.2-mm internal diameter (ID) pipes. Experiments were conducted to investigate the effect of pipe inclination on entrainment fraction in air-water annular flow with inclination angles of 0°, 10°, 20°, 45°, 60°, 75°, and 90° from horizontal. Two techniques were utilized to measure the entrainment fraction: film removal and isokinetic sampling. The experimental results were compared with existing models and correlations, and the best predicting methods were determined for all flow orientations.

An inclination effect on entrainment fraction was observed. This effect occurred at low superficial gas velocities and was more prominent for higher superficial liquid velocities. Using the present study data, the Paleev and Filippovich (1966) correlation was found to be the most accurate in predicting entrainment fraction. Based on all available data, the Pan and Hanratty (2002b) correlation performed the best in predicting entrainment fraction in all pipe orientations. For vertical annular flow, the Oliemans et al. (1986) correlation predicted entrainment fraction more accurately. The Pan and Hanratty (2002b) correlation was most accurate in predicting entrainment fraction for horizontal annular flow. The Wallis (1969) correlation and the mechanistic model developed by Mantilla (2008) most accurately predicted the entrainment fraction for inclined annular flow.
Approach to Selection of the Optimal Lift Technique in the Vankor Field
Authors: Khasanov M. M. , Khabibullin R. A. , Pashali A. A. , Semenov A. A.
Published: February 2011

Artificial lift selection is one of the key decisions to make while starting production of new oil field. Widely used approaches include application range matrixes, decision trees, expert systems based on fuzzy logic. One of disadvantages of all these approaches is a disability to select the most appropriate lift technique; they usually screen out inapplicable techniques and suggest a variety of equally possible solutions. The main purpose of this study was to develop a new approach that will allow selecting optimal lift method based on economical criteria. An approach was tested on Vankor field.

The main idea was to compare different artificial lift techniques applied to the same well using NPV criteria. NPV was calculated as a function of well parameters, fluid properties and AL techniques limitations. Rod Pump, ESP, Gas Lift, PCP as well as natural flowing wells are considered. An application called Technologies Application Pattern (TAP) was developed. Well and fluid parameters as long as economical parameters are used as TAP input; the outputs are optimal flowing bottomhole pressure, oil rate and NPV for each technology considered.

Each of two production layers of the Vankor field has an aquifer and a gas cap. Natural energy is not enough for ensuring target field production profile and gas and water breakthroughs are main challenges for field development. Horizontal wells with high rates were selected for filed development plan. Based on this decision some of AL techniques were considered inappropriate (rod pump and PCP).

The paper discusses main AL selection steps for Vankor oil field. First we consider possible flow rates estimation for each lift technique as functions of GOR, watercut, and productivity index. Based on NPV estimation selection optimal AL is discussed. The final step includes sensitivity and risk analyses. It shows that the solution is more sensible to well depth and GOR. The Monte-Carlo method was used to the risk analysis.

Main results of this work are presented in the form of Technologies Application Map – a two-dimension projection of TAP calculation results. Well parameters are set on the axes of the map. Maximum (optimum) NPV for each lift technique is put on the map. Influence of significant parameters (like oil price) uncertainty AL selection is shown.
Restricted Diffusion Effects in Saturation Estimates from 2D Diffusion-Relaxation NMR Maps
Authors: Zielinski Lukasz , Ramamoorthy Raghu , Minh Chanh Cao , Al Daghar Khadija Ahmed , Sayed Raza Hassan , Abdelaal Atef Farouk
Published: February 2011

A new model is proposed for interpreting two-dimensional diffusion-relaxation nuclear magnetic resonance (2D NMR) maps by including the effects of restriction on the diffusion of water in a connected porous medium. The model's theoretical underpinnings are reviewed and a correlation derived between the diffusion and relaxation of restricted water molecules, i.e., the expected ‘water line’ where the water signal should appear on 2D NMR maps. The main application discussed in this paper is to improve the quantitative separation of different fluids in the formation, leading to better prediction of water and hydrocarbon saturations. In many carbonate formations, the effects of restriction may be quite pronounced making the standard fluid characterization with diffusion-relaxation maps questionable. The restricted-diffusion model is applied to laboratory measurements on carbonate core plugs and to an example log from a Middle East carbonate well where the saturations obtained with the new model are compared against other measures of saturation available in the dataset.
Cost Effective Field Applications Utilizing Coiled Tubing Inflatable Packer System in South Mexico
Authors: Robles Francisco Cazares , De La Fuente Rodriguez Juan Jose , Moreno Angel R. , Noguez Lugo Mario , Tellez Guadalupe , Avilés Rodrigo , Cesin Scarlet , Lian Eric
Published: February 2011

With the discovery of new fields becoming less common and the need to maximize economic recovery in mature fields, operators are trending towards rig-less intervention work to reduce cost and delays to production related to traditional workover rig interventions. With its field complexities, from low bottom hole pressure (BHP) to high temperature/high pressure (HT/HP) reservoirs, and from consolidated sandstone to naturally highly fractured carbonates, and large producing intervals in various flow units with active aquifers, southern Mexico poses a highly significant challenge for rig-less intervention in water control and zonal isolation to assure placement and accuracy of treatment fluids.

This paper discusses the implementations and results of two case histories in which a cost-effective application involving coiled tubing and inflatable packer systems were used for water control in a high water cut producing well and for well abandonment of a newly completed well. The utilization of coiled tubing combined with the inflatable packer is able to precisely deliver the treatment fluids to the zone of interest while the production tubing remains in place, which enhances timely and cost effective intervention solutions1 when compared to workover rig operations.

Case 1 presents the water control application using a coiled tubing inflatable packer system in combination with an organic crosslinked polymer gel, and micro-fine cement slurry for a naturally fractured carbonate reservoir in southern Mexico.

The result of this innovative rig-less approach exceeded the operator's expectations. The case history well was producing 815 BOPD and 5.2 MMSCFD with a water cut of 77%. After the water control treatment with the coiled tubing inflatable packer system, organic crosslinked polymer gel and micro-fine cement slurry, the well was producing 1,459 BOPD and 5.15 MMSCFD with a water cut of 0%.

Case 2 demonstrates a newly completed well with production tubing and packer already set and the well producing with high water cut from an open-hole completion. By using the inflatable packer system through coiled tubing and squeezing cement slurry to abandon the open-hole, a new interval could be perforated and exploited in just 28 hours; in contrast, conventional abandonment with a rig can take up to 10 days.
Optimum Parameterization for Saturation Modeling in Heterogeneous Hydrocarbon Reservoirs Using Well Log Inversion
Authors: Friedel Torsten , Moreno Jaime , Carrillat Alexis , Carnegie Andrew
Published: February 2011

Static or dynamic modeling of hydrocarbon reservoirs requires accurate modeling of the initial water saturation, which is normally a function of local rock quality and the presence of capillary forces. Without understanding how the latter two parameters impact the initial saturation distribution, both initial volumetric estimates and subsequent predictions are potentially meaningless. In the past, well-centric saturation-height modeling was the preferred technique for deriving the saturation model, which was based on regression of selected representative logs or capillary pressure experiments. In brownfields with potentially large numbers of suitable wells, this single-well technique does not leverage on the abundance of available data, which for the purposes of reservoir modeling is also on a more representative scale than core data and potentially covers larger reservoir portions, both aerially and vertically. The idea behind this new approach is to use a full-scale inversion technique integrating all suitable well and core data in a process similar to history matching. Initially, a physical model is developed that describes the saturation anywhere in the reservoir while taking into account different rock types and reservoir regions. With an initial set of parameters based on core observations, the process starts with a sensitivity analysis using Monte Carlo simulation. Insensitive parameters are tied to core data at this stage and the well log inversion procedure commences. For this procedure, an objective function describes the mismatch between the simulated and observed saturation. The model calibration, which is fully automatic using nonlinear solvers, will lead to the set of parameters that best fits core and log-observed saturations. The resulting parametric saturation model can be populated in 3D geocellular models and spatially analyzed in terms of mismatch and uncertainties. A comprehensive statistical analysis of the results helps to understand the role of the individual physical processes such as capillary pressure, as well as to define confidence intervals and cross-correlation between parameters. An example of a large carbonate reservoir with about 100 wells illustrates that the novel saturation modeling approach can contribute to significantly improved reservoir characterization.