bluuebunny/crossref_metadata_2025 huggingface dataset:
Analytical Models to Select an Effective Saline Reservoir for CO2 Storage
Authors: Gupta Abhishek K. , Bryant Steven L.
Published: February 2011

Geological sequestration of CO2 in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The selection among prospective saline reservoirs can be expedited by developing some analytical correlations which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO2 sequestration.

The efficiency of a CO2 sequestration operation depends on risks associated with storage, several of which can be estimated by i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO2 present at any time. A database has been created from a large number of compositional reservoir simulations for different reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip and perforation interval. We use a dimensionless ratio of gravity to viscous forces to formulate different correlations with the factors that contribute to sequestration efficiency. We update a previously reported correlation for time to hit the top seal and develop a new correlation for the maximum lateral extent of the plume using a newly created database for different reservoir and operating properties. A correlation for percentage of mobile CO2 during the buoyancy dominated post injection period is also developed.

We find that normalizing the maximum lateral extent by a characteristic length yields a reasonable correlation with the gravity number. This characteristic length is determined as the maximum lateral distance traveled by plume at any time assuming constant sand face velocity. The correlation confirms that low gravity number allows the plume to travel laterally due to high viscous forces while a high gravity number allows it to move faster in vertical direction due to strong gravity forces. The change in mobile CO2 after injection ends also correlates well with gravity number. We normalize the change in mobile CO2 fraction (or, equivalently, the change in trapped CO2 fraction) after the end of injection by a characteristic CO2 saturation. The characteristic saturation is obtained by considering the volume filled by vertical, buoyancy-driven movement through the area associated with the maximum plume extent.

The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs.
Transient Well Indices: A Link between Analytical Solution Accuracy and Coarse Grid Efficiency
Authors: Archer Rosalind A.
Published: February 2011

A new numerically derived transient well index is presented. This well index is an elegant approach that combines and compares pressure predictions from coarse grid finite difference models and analytical solutions. The ratio of the drawdowns from each solution approach is used to modify the conventional Peaceman well index to produce a new transient well index. The new well index is shown to also be accurate for constant pressure production (i.e. for rate transient behavior) and performs well for a variety of well types, e.g. wells with wellbore storage, partial penetration of hydraulic fractures. Local grid refinements around the well do not produce the same level of accuracy. The new well index can be presented in terms of an equivalent well radius. In late time this becomes the Peaceman well index. The transient behavior of the equivalent well radius is shown to be universal when it is plotted against a dimensionless time function which includes a scaling for the grid size. The new transient well index approach means that coarse grid models can accurately reproduce pressure transient behavior making them a useful tool for numerical well test interpretation.
Theoretical and Experimental Investigation of the Motion of Multiphase Fluids Containing Paramagnetic Nanoparticles in Porous Media
Authors: Ryoo Seungyup , Rahmani Amir R. , Yoon Ki Youl , Prodanovic Maša , Kotsmar Csaba , Milner Thomas E. , Johnston Keith P. , Bryant Steven L. , Huh Chun
Published: February 2011

Paramagnetic nanoparticles are potentially useful for formation evaluation and reservoir monitoring, as they can be induced to move by an imposed magnetic field. Nanoparticles can be designed to have long-term dispersion stability in brine with minimal retention in reservoir rock and with preferential adsorption at oil-water interface. When exposed to magnetic field, they generate sufficient interfacial movements for external detection.

When paramagnetic nanoparticles are either adsorbed at oil-water interface or dispersed in one of two fluid phases co-existing in reservoir rock pores, and exposed to external magnetic field, the resultant particle movements displace the interface. Interfacial tension acts as a restoring force, leading to interfacial fluctuation and a pressure (sound) wave. Our previous work (Prodanović et al, 2010) provided theoretical explanations for the motion of the interface between a suspension of paramagnetic nanorods and a non-magnetized fluid in a cylindrical dish, as measured by phase-sensitive optical coherence tomography (PS-OCT). Here we report on additional experiments carried out with a range of in-house synthesized and surface-modified iron-oxide nanoparticles. The numerical method was improved to be volume conserving for more quantitative matching.

The measurements of interfacial motion by PS-OCT confirm theoretical predictions of the frequency doubling and the importance of material properties, such as magnetic susceptibility, for the interface displacement thus offering insights into behavior in real porous media. With the combined experimental and modeling work, strategies for improved nanoparticle design are developed so that the interfacial, thereby acoustic, response can be magnified.

This laboratory and modeling study is an important step to develop a magnetic field-based method for an accurate, non-invasive determination of multiphase fluids distribution in reservoir rock.
Observations of Thermal and Pressure Transients in Carbon Dioxide Wells
Authors: Paterson Lincoln , Ennis-King Jonathan , Sharma Sandeep
Published: February 2011

Carbon dioxide wells are different to oil, gas and water wells because large density changes due to transient thermal effects can decouple surface pressure from downhole pressure. This means, for instance, that wellhead pressure can decline while reservoir pressure is building after shut-in of a production reservoir. Similarly the opposite can occur. This presents challenges for the interpretation of surface measurements.

An ability to forecast wellhead pressure is desirable for the optimum design of surface facilities for both carbon dioxide production and injection. The interpretation of surface measurements is also useful for monitoring carbon dioxide reservoirs as flow rates are more easily measured at the surface, and surface gauges are more easily replaced if a gauge fails.

Here we report on detailed pressure and temperature observations involving a mixture of 77 mole % carbon dioxide, 20 mole % methane and 3 mole % other gas components. The measurements are from two wells, one production and one injection, involving both surface and downhole gauges. These two wells when connected can act as a strong siphon due to thermal effects. Thermal transients are observed to last up to two months before the surface response matches the downhole response. The use of two downhole gauges in the injection well allows measurement noise to be separated from real pressure events. This in turn allows the performance of the downhole gauges to be evaluated.

The results are useful for input into the engineering design of future carbon dioxide facilities and the use of surface pressure for interpreting reservoir behavior.
4D Seismic History Matching of a Real Field Case with EnKF: Use of Local Analysis for Model Updating
Authors: Fahimuddin Abul , Aanonsen Sigurd Ivar , Skjervheim Jan-Arild
Published: February 2011

Quantitative incorporation of 4D seismic data into reservoir history matching is an attractive proposition. The use of ensemble Kalman filter (EnKF) in this regard improves overall quality of seismic data matching and estimating reservoir parameters. We performed 4D seismic history matching of a sector model based on a North sea reservoir using real inverted 4D impedance data. Special challenges are involved when we assimilate large amount of in EnKF, and hence, a methodology based on a combination of global and local analysis scheme is used. In history matching process, we have focused on matching the acoustic impedance ratio between two time steps of several years of production. A petro-elastic modeling based on rock physics recipe of North sea reservoir is used. Uncertain reservoir parameters considered are porosity and permeability. Updated dynamic variables (pressure and water saturation) are conditioned to both production and seismic data. The large number of measurements introduced by the integration of 4D seismic data is handled by an efficient EnKF scheme with the possibility to perform localization. Global and local analysis schemes assimilate production data and seismic data respectively. In our implementation of local analysis, we used three significant regions based on flow conditions and seismic data within a given local analysis region is influenced by only variables in the same region. The posterior ensemble of models showed good match to both production data and seismic data. In most of the cases of reservoir characterization, the combined use of 4D seismic with production data improved history matching for the wells and also improved posterior impedance ratio data matching. In addition, 4D seismic data provided more information related to permeability update in the aquifer and in-fill areas. The results indicate that the proposed local analysis-based model updating scheme reduced the amount of spurious correlations and tendencies to ensemble collapse seen with global analysis.
Continuous Pig Lift: A New Artificial Lift System and Its Field Pilot Test
Authors: Zhong Haiquan , Li Yingchuan , Yu Xin , Wang Zhibin
Published: February 2011

Pig lift was firstly proposed and successfully applied in five wells in Brazil in 1996. Pig lift exhibits many advantages over other artificial lift systems, particularly for the wells with high viscosity oil, waxy oil, high gas-liquid ratio, low pressure and/or low productivity. However, one of its biggest restrictions is that the well has to use a U-shaped double completion string if a pig lift system will be installed, as a result, it is impossible to effectively use formation gas for lifting, and a high-pressure gas resource is needed. In addition, pig lift as an intermittent production method requires well periodical opening and shutting-in, which limits well productivity and increases management difficulties.

This paper develops a new artificial lift system, continuous pig lift, by the use of a single completion string with a series of eccentric units. Retaining all the advantages of the current pig lift, the new system allows the pig to fall from the annulus between the tubing and casing down to the downhole tubing coupling. A valve device is designed to cut off both high and low pressures in the wellhead and launch the pig. With no need of extra gas resource, this system effectively uses formation gas to push the pig into production string and achieves continuous production.

The developed system was installed in one well in Sichuan Gas Field of China. The system is stable and has significantly increased production rate in comparison with conventional continuous gas lift. Through various field pilot experiments, pig size, type and launching frequency are found to be key factors dominating the performance of a continuous pig lift system and the optimum values of those factors are then determined.
HZ 25-4 ERD Challenging Drilling Project - New Strategy and New Technology Implementation Are the Keys to Improved Drilling Performance
Authors: Hong Lian Ji , Scaruffi William , Brewster T Wayne , Balka Sarfraz M.
Published: February 2011

CACT-OG is a joint operating company consisting of CNOOC, ENI, and Chevron as its Principal Companies. CACT- OG is the operator of Huizhou HZ 25-4 oilfield in South China Sea, which was discovered in December of 2005 as multiple oil bearing zones found in the vertical exploratory well drilled by a semisubmersible rig. HZ 25-4 field is located in block 16/19 in central area of Pearl River mouth basin, located 6 km southwest of the HZ 19-2 platform in a water depth of 102 meters. After discovery, extensive studies were conducted for the development of this field. It was decided to upgrade the existing drilling rig on the nearby HZ 19-2 field platform and drill extended reach (ERD) wells from the platform. Three of five ERD wells were drilled and completed with 6" horizontal laterals and stand alone screens for sand control.

A number of challenges appeared while drilling these wells including: ERD drilling experience level, excess torque and drag, hole instability, hole cleaning and resulting pack off, high side force and casing wear, high ECD due to shallow TVD, losses due to high ECD and fault encounter, and shock and vibration. The result of these challenges was long times to complete the wells and excess budget overruns. After the completion of the third well, it was been decided to suspend the operations and perform detailed analysis on the challenges with extensive lessons learned in order to approach the remaining two ERD wells in the Plan of Development with a different strategy.

Following the studies and drilling analysis, the revised final plan included a new engineering design, revised operations procedures and monitoring, new approach for team building and training, and implementation of newer technologies such as utilization of Aluminum Drill Pipe and Continuous Circulating Devices. The result of the new plan applied has been a dramatic improvement in performance and consistent savings in budget. It has been observed that this different drilling approach and technology has opened a new window on how to drill challenging ERD, and that is a key to improved drilling performance.
Analytical Tools Aid Understanding of History-Matching Effort in a Fractured Reservoir
Authors: Kabir C. S. , Boundy F.
Published: February 2011

Many equiprobable solutions exist while history matching a reservoir's performance, given the ill-posed nature of the inverse problem. To mitigate some of the uncertainty issues stemming from the initial static reservoir description, this study shows how continuous learning evolves when a slate of analytical tools are used while interpreting real-time surveillance data. The combined approach involving the use of analytical tools in conjunction with numerical simulations helps understanding reservoir performance, which, in turn, allows insights into history matching. Specifically, we demonstrate the use of various analytical tools to learn about (a) time-dependent behavior of both producers and injectors with rate-transient analysis to assess an evolving waterflood, (b) reservoir heterogeneity with pressure-transient analysis, (c) degrees of time-variant injection support with the reciprocal-productivity index, (d) injector-producer connectivity with the capacitance-resistance model, and (e) real-time injection-well behavior with the modified-Hall analysis.

The benefits of collective use of analytic tools demonstrate that they should be used either simultaneously or preferably before undertaking a detailed numeric flow-simulation study, particularly where real-time data are being gathered. In particular, the lack of performance match for the entire history with a numerical model becomes transparent when the learning from analytical tools is juxtaposed. This understanding paves the way for much improved learning of reservoir plumbing.
Crosswell Electromagnetic Inversion Constrained by the Fluid-Flow Simulator
Authors: Liang Lin , Abubakar Aria , Habashy Tarek M.
Published: February 2011

Crosswell electromagnetic technology has been developed for reconstructing the formation resistivity distribution of the subsurface. By looking at the resistivity changes over time, one can monitor the fluid front movement and estimate saturation changes in the reservoir. Traditionally, the resistivity distribution is directly inverted from the crosswell electromagnetic data through an inversion process. However, this inversion process can be non-unique and has limited spatial resolution.

In this paper, we introduce several inversion approaches for improving the interpretation of the crosswell electromagnetic data. The inversion is constrained by a multiphase fluid flow simulator that models the fluid flow in the reservoir and constructs the spatial distribution of the water saturation and salt concentration, which are in turn transformed into the formation resistivity using a resistivity-saturation formula. In these approaches, instead of directly inverting the resistivity distribution, we invert the formation petrophysical parameters such as permeability and porosity.

Three inversion approaches were explored. The first is the model-based approach that inverts a layer-by-layer distribution of permeabilities and porosities. The second is the pixel-based approach in which we assume that the formation permeabilities are known and hence we invert only a cell-by-cell distribution of porosities. The third is a hybrid approach in which we invert a cell-by-cell distribution of porosities together with a layer-by-layer distribution of permeabilities. By using these approaches, we obtain a reconstructed resistivity distribution that is consistent with the fluid flow physics, and the spatial resolution is significantly improved. Additional outcomes of the inversion include the saturation spatial distribution, which provides an explicit indication of fluid movement within the reservoir. The results of synthetic case studies show significant improvements compared with those acquired by the traditional approach.
Joint History Matching of Production and 4D-Seismic Related Data for a North Sea Field Case
Authors: Gervais V. , Roggero F. , Feraille M. , Le Ravalec M. , Seiler A.
Published: February 2011

This paper shows the results of an assisted history-matching process applied to a North Sea field case operated by Statoil. The dynamic data considered, that is the data varying with fluid flow, are both production data and 4D-seismic related data.

The history-matching process entails a geology to fluid-flow simulation workflow, including the population of the geological model by facies and petrophysical properties using geostatistical algorithms, the simulation of fluid saturation and pressure changes in the reservoir and the computation of time-lapse seismic attributes. This workflow also addresses scaling issues: upscaling of petrophysical properties from the fine geological grid to the reservoir coarse grid; pressure and saturation downscaling from the reservoir grid to the geological grid where a petro-elastic model is applied to compute the seismic related attributes. A least-square objective function is defined to measure the mismatch between the measured dynamic data (production and 4D seismic-related data) and the corresponding simulated responses. Then, a gradient-based optimization algorithm is run to minimize this function, perturbing parameters identified as uncertain from a preliminary sensitivity study based upon Morris's method. To ensure the overall consistency of the workflow, the perturbations applied to the selected parameters are propagated all along the workflow.

This methodology was applied to a North Sea field case. A good production data match was obtained perturbing the spatial distribution of some facies and petrophysical properties. The implemented perturbation process was driven by the gradual deformation method: many likely distributions were combined all together leading to a more suitable distribution, which still honored the statistical properties of the model. The match of the available 4D seismic-related data was also locally improved. In addition, the use of 4D seismic data on top of production data made it possible to reduce the data misfit at some wells.

This study shows the ability of the assisted history-matching process to handle both production and 4D seismic data on a real field case.
Advanced Technologies and Practical Guidelines for Challenging Drilling Applications
Authors: Jellison Michael , Spoerker Hermann , Chandler R. Brett , Abashin Valentin
Published: February 2011

This paper provides a review of recent technology advancements and addresses practical considerations associated with drillpipe and drill stem components for extreme drilling applications. Ultra-high torque double-shoulder rotary connections are often employed in these applications potentially complicating proper design and material selection for cross-overs, top-drive subs, pup joints and other accessories. These new connections often employ materials with higher strength requirements than standard API connections. The paper outlines recommendations for material strength and design parameters for various drills stem accessories. The latest generation of high angle and extended reach wells are encountering significantly higher side loads between the drillpipe and casing creating unprecedented levels of casing wear. Proper hardband selection, application and maintenance are essential to successfully and safely drill these critical projects. Hardband system trends for critical applications are highlighted, and recent hardband casing wear and tool joint protection test results obtained using an advanced hardband wear machine are discussed.

Due to the dramatic increase in oil prices the industry has seen a re-emergence of deep and ultra-deep drilling projects that encounter H2S gas. The paper provides an update on the latest sulphide stress cracking resistant drillpipe grades along with initial results from a study of the effect on S-grade drillpipe samples to various H2S exposure concentrations, representing typical conditions when circulating a gas kick to surface. Sour service drillpipe, built with SSC resistant upset tubes and tool joints, has been available for some time. The friction welds joining the upset tubes and tool joints were not resistant to SSC. This paper presents the successful development and qualification of SSC resistant friction welds for critical sour applications. The surge in critical drilling has led to an increasing trend of drill stem friction heating failures. The paper includes characteristic features of these failures along with case histories and prevention methods.
Automated Field Development Planning in the Presence of Subsurface Uncertainty and Operational Risk Tolerance
Authors: Tilke P. G. , Banerjee R.. , Halabe V. B. , Balci B.. , Thambynayagam M.. , Spath J..
Published: February 2011

This paper presents an automated workflow to accelerate the well placement planning process in the presence of subsurface uncertainty and operational risk. The system allows the user to screen and rank development options in minutes.

This automated field development planning system is an optimization application, integrated with a larger seismic-to-simulation workflow. A key piece of technology in this system is a high-speed semi-analytical reservoir simulator, which enables an optimal strategy to be computed very rapidly. The system also embeds key technologies for optimization in the presence of uncertainty and risk which leverages an advanced uncertainty framework.

The workflow starts with a reservoir model, along with existing wells and other operational constraints. Oil or gas production is computed using the high-speed reservoir simulator. Proposed well trajectories honor operational constraints, such as facility processing, water injection capacity, borehole dogleg severity, anti-collision with existing wells, and hazard avoidance on the surface and in the reservoir. The optimal strategy proposes well surface locations, trajectories, and completion locations and is calculated by optimizing the value e.g., net present value (NPV) or production.

This new methodology has many applications in the field development planning context. We are able to rapidly screen multiple field development planning scenarios and produce an optimal new/infill drilling strategy with primary production or waterflooding consisting of both newly proposed and existing wells. The final result includes performance predictions based on an optimized field development plan (FDP), risk, and subsurface uncertainties. The most promising scenarios can if necessary be used subsequently for detailed numerical simulation in order to validate results.

The value of this automated field development planning workflow, along with support for pattern, pad, and platform based strategies, is proved by its use on a variety of onshore/offshore mature and green oil and gas fields with wells in primary production and waterflooding environments.
Multiple-Opening Diverter Tool Reduces Formation Surge Pressure and Increases Running Speeds for Casing and Liners
Authors: Scott Thad , LoGiudice Michael , Gaspard Greg , Vidal Daniel
Published: February 2011

When running casing in deepwater/subsea applications or in liner deployments, excessive surge pressure in the wellbore can occur when drilling fluid in auto-filled casing is forced through the drillpipe landing string to surface. The resulting friction losses can increase the equivalent mud weight (EMW) sufficiently to exceed the fracture gradient of the formation and often results in fluid losses that could lead to well-control issues. Surge reduction tools mitigate this problem by introducing ports in the drillpipe above the casing or liner running tools. The auto-filled fluid can then be diverted through the ports into the annulus, allowing the casing or liner to be run much faster without the risk of surging the formation excessively. Until recently surge tools have been run in the open position, allowing the tool to divert fluid at all times; however this prevents circulation in the event that the casing or liner needs to be washed down upon encountering an obstruction downhole. Furthermore, should a well-control situation occur, the tool must be closed permanently by intervention from surface and can no longer divert fluid once wellbore control is achieved.

To address this shortcoming, a multiple-opening diverter tool has been developed that is initially run into the wellbore in the closed-port position, allowing the system to have complete pressure integrity. The ports are covered by an unbalanced sleeve, which, as auto filling occurs, is opened by a small differential pressure created within the tool, diverting fluid as necessary. Once auto filling stops, the sleeve returns to its original position, and the ports are automatically closed off, enabling the string to be circulated without permanently deactivating the tool. In addition, the ports remain closed should a well-control situation occur.

In this paper the authors will review the evolution of casing fill control equipment, discuss the issue of controlling losses while running a tubular, and describe the features of this new multiacting surge-control tool. They will conclude with a case study of its use and effectiveness.
Pitfalls in the Evaluation of Unconventional Resources
Authors: Haskett William J. , Brown P. Jeffrey
Published: February 2011

There is significant current commitment within the industry to develop and implement methods to assess the prospectivity of Unconventional Resource opportunities. The purpose of this paper is to identify some of the common recurring errors in both numerical evaluation and operational priorities, with specific examples.

Efficient planning and evaluation of Unconventional opportunities is critical due to the low margin, high capital nature of the business. Converting the Conventional exploration and development mindset over to one that places high value on project management and manufacturing efficiency is difficult. Appropriate evaluation and applied operational learning are critical to evaluating decisions that can mitigate downside risk, including the critical post-pilot go/no go decision.

Some Specific trouble points are:

Attempting to model future program results with a single distribution of individual well EUR results-predicting the unpredictable with unwarranted precision. Force fitting a lognormal distribution through datasets that are decidedly non-lognormal, particularly in the outer portions of the probability space. The ‘double whammy’ of prediciting an overpopulation of high volume wells (including unrealistically high recovery wells) and underpopulation of low volume wells results in overestimation of results… often significantly so. Overemphasizing assessment of chance of geologic success, when the key questions to resolve are the chance that the significant risked (pre-pilot) investment will lead to a ‘go’ decision, how often does a particular pilot design correctly predict viability or non-viability-and what the chance is that the entire venture will be an economic success. Failing to recognize the critical success factor-production profile uncertainty – and model this correctly, and develop appropriate prioritized learning objectives for the pilot. Ignoring the impact of business pinch-points, the scarce resource items which when controlled provide profit assurance and distinct competitive advantage.

The failure to link the statistical assessment to operational priorities on project assessment or Play entry relegates business sense to an after-thought. The unfettered, unfocused "drill it and see what happens" approach results in sub-optimal pilots that fail to provide appropriate confidence for critical business decisions, destroys value, and risks loss of competitive advantage in an Unconventional Play.
A New Method for Predicting the Total Vertical Stress Field and Formation Pore Pressures
Authors: Ozan Cem , Brudy Martin , van der Zee Wouter
Published: February 2011

Estimation of formation pore pressure requires the knowledge of the overburden load in an area, which is commonly determined by vertical integration of density data. In fields where the total vertical stresses are significantly affected by topography (e.g., onshore valleys, sub-sea canyons) or lateral density variations (e.g., salt domes), the vertical integration can over- or underestimate total vertical stresses which can lead to over- or underprediction of pore pressures. In this paper, to improve the accuracy of the overburden stress estimations in areas of complex topography and lateral density variations and subsequent the pore pressure predictions, we present a new method to calculate total vertical stresses which utilizes an analytical solution to calculate the contribution of each volume element on the vertical stress field. We also perform finite element analysis for two different geographic cases, quantify the error in pore pressure predictions and compare the results of finite element analysis with those of the proposed method. Moreover, we employ the method proposed in this paper to calculate overburden stresses in two case studies which are developed based on field data.

Our results show that the effect of topography and lateral density variations on the total vertical stress field can result in significant errors in pore pressure predictions if the total vertical stresses are calculated by vertical integration. On the other hand, the total vertical stress calculated by the proposed method are in good agreement with finite element analysis results and the improved method provides a framework to enhance pore pressure predictions.

The proposed method does not require any complex processing of data and calculation times are lower relative to finite element and finite difference analysis. Moreover, the proposed method requires only 3-D density distribution and spatial information about the discrete domain (i.e., dimensions of the volume elements), which are also required for overburden stress estimation using the vertical integration method. In other words, the proposed method improves the pore pressure prediction workflows by refining the overburden calculation algorithm.
Carbon Dioxide Corrosion When Least Expected: Importance of Carbonate Chemistry in Stress Corrosion Cracking on the External Surfaces of Martensitic Stainless Steel Production Tubing and Low-Alloy Carbon Steel Pipeline
Authors: McKennis Jeffrey S. , Bae Nam , Termine Enrico J.
Published: February 2011

Unexpectedly, numerous stress corrosion cracking failures of production tubing have occurred from the external surface (annular side), rather than from the internal (production side). This problem is encountered frequently in HPHT wells and is termed annular environmentally assisted cracking (AEAC). Studies of these failures have pointed to an incompatibility between the metallurgy of the tubing and the completion/packer fluid placed in the annulus. Simplistic causative factors such as a chloride ion-metal interaction are insufficient to explain the AEAC failure mechanism.

In contradistinction, our research studies on the compatibility of martensitic stainless steel production tubing with a large variety of completion/packer fluids have implicated specific fluid contaminants as key causative factors. Of these contaminants, CO2 and/or its aqueous counterparts (carbonate, bicarbonate or carbonic acid) play a major role. Quite unexpectedly, the presence of bicarbonate/carbonate ion produces cracking in sodium bromide brines, which are often believed to be free of cracking issues.

Similarly, occurrences of stress corrosion cracking on the external surface of pipeline have been reported since the late sixties. In these instances the bicarbonate ion in groundwater has also been assigned a major role.

This paper focuses on the important role of CO2 chemistry in explaining the observed cracking for the two different environments. The unique interactions of CO2 and its basic counter parts HCO3− and CO3−2 with the completion/packer fluid (high salt concentration, divalent cations, etc.) and its relevance to the tubing failures are discussed. Comparison is made to the fluid chemistry responsible for pipeline cracking. Chemical mechanisms to explain the role of bicarbonate/carbonate in the observed tubular cracking are presented.

The study describes the importance of fluid and CO2 chemistry in localized corrosion and stress cracking of diverse metallurgy, advancing our knowledge of the ubiquitous CO2 corrosion issues.
Hydraulic Submersible Pumps: 10 Years Experience on a Heavy-Oil Field in the North Sea
Authors: Mali Gwyn , Morrison Alan , Green Alex , Graham Ronald , Harden William
Published: February 2011

Captain is a heavy oilfield in the North Sea operated by Chevron North Sea Limited, which has utilised Hydraulic Submersible Pumps (HSPs) for over 10 years. To date, the field has developed over 20 subsea wells with HSPs to complement the more established Electrical Submersible Pumps (ESP) technology used on the field's platform wells.

Hydraulic Submersible Pumps are an alternative to Electrical Submersible Pumps that use pressurised water as opposed to electricity for power. The Captain HSPs utilise separated produced water supplied from the surface that is delivered down the annulus to drive turbines on the pumps, where the water is then commingled and produced with the fluid from the reservoir.

The application of HSPs on Captain has realised several benefits through the use of the technology, including: an ability to handle a wide range of flow rates, GORs and water-cuts; good pump run lives; and relatively simple installation in the subsea environment.

This paper shares the operating experiences and presents the lessons learned based on field performance of the HSPs on the Captain Field.
ASP Flooding of Viscous Oils
Authors: Kumar Rahul , Mohanty Kishore K.
Published: February 2011

The goal of the present work is to develop alkaline-surfactant-polymer (ASP) methods to improve recovery of viscous oils. Phase behavior tests of a viscous oil (330 cp) with alkali surfactant formulations was performed to determine conditions for obtaining high solubilization ratio (thus ultra low IFT) and avoid viscous emulsions. The selected alkaline-surfactant system was tested in a sand pack flood. A partially hydrolyzed polyacrylamide polymer was used as a mobility control agent in and behind the surfactant slug. Phase behavior with high solubilization ratios was obtained with a combination of alkali and surfactant at 25°C. Waterflood had an early breakthrough at about 0.3 PV and recovered about 0.61 PV of oil in 3 PV throughput. Injection of tertiary alkaline-surfactant-polymer slug followed by tapered polymer slugs could recover almost 100% of the oil. The pressure drops were reasonable (<2 psi/ft) and depended mainly on the viscosity of the polymer slugs injected.
Comparison of Inflow Performance and Reliability of Open Hole Gravelpacks and Open Hole Stand-Alone Screen Completions
Authors: Burton Bob , Hodge Richard
Published: February 2011

Open Hole Gravelpacks and Open Hole Stand-Alone Screen Completions are used in many high rate oil and gas wells. Selection criteria for determining the applicability of these alternative completion techniques tends to be company specific with proponents of Open Hole Gravelpacks claiming significantly better productivity and reliability than Open Hole Stand-Alone Screens. Review of laboratory and field data in this study shows these claims to be erroneous.

This paper presents results of well productivity studies from field and laboratory data comparing Open Hole Gravelpack and Open Hole Stand-Alone Screen flow performance. Key completion design and installation parameters driving performance for each completion type are indentified and discussed. Field well life and reliability data are also reviewed to show that properly designed and installed open hole completions have reliability statistics similar to those seen in cased hole gravelpacks and frac-packs.

Design criteria using an integrated reservoir characterization, laboratory testing and field installation procedure are provided to allow better selection between Open Hole Gravelpacks and Open Hole StandAlone Screen completions.
Modeling CO2 Injection Including Diffusion in a Fractured-Chalk Experiment
Authors: Alavian S. A. , Whitson C. H.
Published: February 2011

This paper presents a modeling study of CO2 injection in chalk core based on laboratory data reported by Darvish et al. (2006). The experiment consisted of a vertically-oriented 60-cm long chalk outcrop core initially saturated with live reservoir oil at 130 ºC and 300 bar. After saturating the core with the oil mixture by displacement a small fracture volume surrounding the core was created by heating the solid Wood's metal that originally filled the volume between the core and core holder. Then CO2 was injected for 22 days. The experiment was performed at a pressure above the minimum miscibility pressure (MMP) as defined by a traditional 1D multi-contact displacement process (MMPlD).

Our modeling study was conducted with a compositional reservoir simulator. The 2D r-z model used fine grid for the core matrix and surrounding fracture. The match of reported production data gave a high degree of confidence in the model. Also, produced mass fractions of components measured periodically during the experiment were matched. The compositional data fit was sensitive to the modeling of diffusion and the EOS model fit to depletion and swelling test data which included oil and gas mixtures with a clear definition of a critical transition.

Our study indicates that gravitational drainage affected the recovery process for CO2 injection in the Darvish experiment, but also mass transfer by vaporization, condensation, and molecular diffusion.

The injection of CO2 in North Sea fractured chalk reservoirs is of keen interest, as a secondary and tertiary recovery process (e.g. in Ekofisk and Valhall). Proper modeling of experimentals such as the Darvish tests is not only a step to understand local (microscopic and matrix-fracture interaction) recovery phenomena, but also as an important step in model upscaling for pilot and full-field projects.
Assessing Reservoir Connectivity through Biomarker and Bulk Compositional Gradient Analysis
Authors: Pomerantz A. E. , Cañas J. A. , Peters K. E. , Mullins O. C. , Koerner K. R. , Auman J. B. , Curry D. J.
Published: February 2011

Reservoir connectivity is among the most important risk factors in deepwater environments and cannot always be identified by traditional techniques such as pressure surveys, petrophysical logs, and geochemical fingerprints. Here we describe a workflow in which reservoir connectivity is assessed through a combination of traditional techniques, compositional gradient analysis, and geochemical evalution of reservoir history. That workflow is demonstrated in a case study in which compositional gradients are detected by optical spectroscopy (which provides a precise measurement of asphaltene content) and viscosity measurements. These gradients are interpreted in the context of the modified Yen model, which characterizes different aggregatation states of asphaltenes and can be used to predict the magnitude of asphaltene content gradients in condensates, black oils, and heavy oils. Additionally, fluid composition is studied with two sophisticated laboratory techniques: comprehensive twodimensional gas chromatography, which measures the detailed composition of the nonpolar fraction of petroleum, and electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry, which measures the detailed composition of the polar fraction of petroleum. These complentary techniques provide a detailed picture of the composition of almost the entire crude oil, enabling confident biomarker identification and analysis. In this case study, a series of 25-norhopanes and mildly altered normal and isoprenoid alkanes were detected, suggesting the reservoir has experienced multiple charges and contains a mixture of oils biodegraded to different extents. Compositional gradients and interpreted reservoir history are consistent with a connected reservoir in which the observed viscosity variation originates from gravitational segregation of asphaltene nanoaggregates in a crude oil with high asphaltene concentration resulting from a biodegraded charge. This combination of traditional techniques, analysis of compositional gradients delineated by optical spectroscopy, and sophisticated laboratory measurements allows connectivity to be assessed with greater confidence than otherwise attainable during exploration and appraisal.
Building Effective Training Models for Today’s Global Challenges
Authors: Fiffick William S. , Kenner Claude W. , Susko David
Published: February 2011

In today's global business, the ability to effectively train and develop the people we need is vital to our success. New training technologies do broaden our reach, but technology alone is seldom sufficient to achieve our goals. Too many times "learning technology" is deployed as a "solution" rather than as a component of a learning strategy. Therefore, developing a learning strategy is key. Taking that strategy, and building the appropriate training models, helps enhance the ability to effectively develop the Human Capital we need.

In some cases, a single development model may be sufficient. But to be successful globally one must consider: language, location, culture, economics and a host of other issues.

So we begin by asking questions. Do we have accurate competency models? What motivates our people to learn? Who makes up our audience? (Are we just training our employees, or are there other "partners" in need of training?) How do we sustain our training and development programs? How can we ensure better consistency in our programs? How do we support learning globally? What role should "learning technology" play in these efforts? How do we ensure local training standards are still in place? How should we measure our progress?

Asking and answering these kinds of questions helps build the models needed. These queries can help us engage minds from the Executive ranks, Management, Operations personnel, Engineering & Technology, as well as, Human Resources and more. We can then build more effective models by ensuring the best ideas are brought into the fold.

The following is a case study detailing how a leading global organization is building effective training models. Although the main focus is on the processes employed, best practices, and lessons learned are examined and discussed.
Kinematic Hardening Characterization: Applications to Solid Expandable Tubulars
Authors: Durivault J. , Bernard J. , Desdoit E. , Bureau-Bayart A.-S. , Villani A.
Published: February 2011

This paper discusses an enhanced method to predict expandable tubular performance such as collapse and connection sealability. It presents the implementation of the hardening characterization into FEA. The enhanced modelling was then applied to study specific applications, i.e. post-expansion collapse and loads cycles on expanded threaded connections.

The hardening induced by the cone (or any other solid expansion process) creates anisotropy and deeply modifies the grade properties: the tensile-compression tests and first fatigue cycles enable to characterize the material state vs. the rate of deformation. The tests highlight the Bauschinger effect in the material after plastic deformation. Since the material state after hardening depends on the deformation path, and that this memory effect is not accounted for in standard finite element analysis (FEA) models, a parametric model of kinematic hardening has been developed to match the mechanical tests observations for each grade. The integration of hardening effects on the expanded material properties improves significantly the FEA modelling results. It is one of the main causes of the post-expansion collapse pressure decrease, as illustrated by the FEA results using the enhanced hardening law that matches closely test results of expanded pipe collapse. Significant variations in the FEA results on expandable connections during post expansion cycle loads were observed.

The understanding of hardening effect on material properties is the key to design and improve the expandable tubular products (casing, connections). The material knowledge after expansion and the enhanced material FEA modelling allow predicting accurately the behaviour and performances of expandable tubular products used in expandable tubular applications.