bluuebunny/crossref_metadata_2025 huggingface dataset:
Reactive Pore Network Modeling Dedicated to the Determination of the Petrophysical Property Changes while Injecting CO2
Authors: Algive Lionnel , Bekri Samir , Vizika Olga
Published: October 2009

A Pore Network Model is an efficient tool to account for phenomena occurring at the pore scale. Its explicit threedimensional network of pores interconnected by throats enables to easily consider the topology and geometry effects on upscaled and homogenized petrophysical parameters. In particular, this modeling approach is appropriate to study the rock/fluid interactions. It can provide quantitative information both on the effective transport property modifications due to the reactions and on the structure evolution resulting from dissolution/precipitation mechanisms.

The developed model is based on the resolution of the macroscopic reactive transport equation between the nodes of the network. By upscaling the results, we have then determined the effective transport properties at the core-scale. A sensitivity study on reactive and flow regimes has been conducted in the case of single-phase flow in the limit of long times.

It has been observed that the mean reactive solute velocity and dispersion can vary up to one order of magnitude compared to the tracer values because of the concentration profile heterogeneity at the pore scale resulting from the surface reactions. As for the reactive apparent coefficient, when the kinetics is limited by the mass transfer, it can decrease by several orders of magnitude with regard to the one calculated by the usual perfect mixing assumption. That is why scale factors should be added to the classical macroscopic transport equation implemented in reservoir simulator to accurately predict the reactive flow impacts. For each study case we have also obtained the permeability variation versus the porosity evolution in a physical way which accounts for reactive transport conditions. It appears that the wall deformation pattern and its impact on petrophysical properties must be explained by considering both microscopic and macroscopic scales of the reactive transport, each one governed by a dimensionless number comparing reaction and transport characteristic times.

This work contributes to improve the understanding of surface reactions impacts on reactive flow in one hand, and on permeability and porosity modifications in the other hand. Using the PNM approach, scale factors parameters and permeability versus porosity relations can be determined for various rock-types and reactive flow regimes. Once integrated as inputs in a reservoir simulator, these relations are a powerful and convenient means to enhance the modelling accuracy of the petrophysical properties evolution during a reactive fluid injection such as CO2-rich brines.
Established Knowledge Management (KM) Communities of Practice: Moving Across the KM Product Life Cycle
Authors: Burress Charlotte , Paylow Kevin
Published: October 2009

Communities of practice (COPs) are a sub-set of knowledge management (KM) that provide a channel for people to interact and collaborate to achieve common goals. Benefits of COPs include global problem solving, leveraging best practices, time savings, and identifying future leaders. Since the global adoption of COPs and KM efforts in our industry, most companies have seen a rapid decline in community activity after initial deployment resulting in KM becoming a failed corporate initiative. In the product life cycle, these communities did not make the jump from the introduction to the growth phase. Some KM efforts and COPs do survive to the growth phase; however these established communities are not progressing along the life cycle curve due to little or no continual growth in activity levels and early adopters representing the bulk of users. The challenge for established COPs is to not just sustain activity levels but to create value for more users which will thus enhance the COPs’ significance to the global organization.

This paper discusses the effects of several methods used to progress COPs along the product life cycle, moving users from casual bystanders to active participants in discussion. Specifically, adopting Web 2.0 technology provides new ways to engage users to define value-added content, leverage social networking, and embrace collaboration. In addition to implementing new web-based technologies, a full-time knowledge transfer facilitator or knowledge broker fosters the growth of the community. Lastly, over time established COPs tend to gel around certain employee populations, and the knowledge broker must break these arbitrary barriers and engage other users in the organization such as supply chain management or laboratory personnel. With the combination of these methods, the COPs have been shown to progress along the product life cycle with increased adoption and added value for the organization.
Development of a Geomechanical Reservoir Modelling Workflow and Simulations
Authors: Bostrøm B.
Published: October 2009

A Geomechanical Earth Model (GMEM) is wanted for every field development and should be maintained for the life-time of the field. These models are needed in order to contribute to safe and optimum drilling and production in depleting and complex reservoirs. This strategy is only possible if an automated workflow is developed.

Links between the stress simulator Abaqus and the geological software Irap RMS and between Abaqus and the reservoir simulator ECLIPSE are established in order to have; (1) faster and better generation of geomechanical reservoir simulation models, (2) to better account for geomechanical effects in the reservoir simulation and 4D feasibility studies. Abaqus scripting interface is used to link Irap RMS and Abaqus. The link consists of a set of Python scripts that rebuilds the reservoir geometry in the CAD, meshing and visualization program Abaqus/CAE. This is believed to be a unique feature of the developed workflow as opposed to earlier developments that reuse the reservoir grid. In addition, a link between Abaqus and ECLIPSE is developed transferring reservoir pore pressure data, initial porosity and degree of water saturation between ECLIPSE and Abaqus through the file system. Verification and demonstration of capabilities of the developed workflow is done using a faulted North Sea oil and gas field.
Technology for Determining Reservoir Pressure from Mud Log Gas Improves Mature, Tight Gas Asset Performance: A Case Study of Ada Field, North Louisiana
Authors: Lapierre S. G. , Prine B. H. , Pickrel H. M.
Published: October 2009

A mature tight gas field in North Louisiana that experienced dwindling performance and erratic predictability spurred the creation of an alternative technology that boosted production rates and minimized completion costs. An average production rate uplift of 108% shown on three wells resulted from modifications to mud logging operations; careful interpretation and integration of data; and the addition of new, proprietary transforms. The resultant technology provided a variety of useful information with little or no additional cost or mechanical risk.

When conventional wireline technology proved both technically and economically unsuccessful, an alternative technology was needed to determine reservoir pressure from mud log gas with sufficient resolution to support zone selection, completion design, and the identification of bypassed pay. This document describes the proprietary technology and a variety of specific applications employed by the development team. Production logs and conventional pressure measurements demonstrate the performance increases achieved by incorporating this technology into the development program.
How to Avoid Shale Intervals in the Grane Reservoir by Utilizing Real-Time Geosteering Data and Openhole Sidetracking
Authors: Bakka Marit , Rønning Johan Knut , Sæbø Asbjørn , Jensen Kåre , Sæverhagen Erland , Erichsen Cato
Published: October 2009

The Grane reservoir consists of massive turbidite sand deposits with intercalated shale bodies related to deformation of the reservoir and encasing shales. When drilled, these shales often become unstable after some time, resulting in packoff and collapsed hole, leaving planned produced intervals unrecovered. To maintain oil production from the Grane field, wells are drilled to compensate for declining production. Different strategies to stabilize the shale intervals have been unsuccessful.

Real-time geological information collected while drilling are interpreted and used to understand the shape and extension of the unstable shale bodies in the context of the seismic data. This interpretation is based on azimuthal resistivity and gamma as well as extra deep reading resistivity. Using this information, the drilling system is pulled back into the sand section in front of the unstable shale and an openhole sidetrack is performed. Based on the updated interpretation of the geological data gathered while drilling through the shale, the new wellpath is designed to avoid the shale interval and penetrate reservoir intervals farther out.

Openhole sidetracking is performed using the main 3D rotary steerable system (RSS) drilling bottomhole assembly (BHA). No cement plugs, ramps or kickoff BHAs are required, resulting in significant time savings. This method is proven on a number of wells and is today a part of standard well-planning on Grane.

The applied method is so far the most efficient way to increase the length of the productive intervals and has proven to be a reliable and low-risk operation with a high probability for success. This paper will describe how the combination of real-time geological information and possibilities to perform openhole sidetracks are systematically used to increase the reservoir sections on Grane.
Multicomponent Advisory System Can Expedite Evaluation of Unconventional Gas Reservoirs
Authors: Wei Y. N. , Cheng Kun , Holditch S. A.
Published: October 2009

Producing natural gas from unconventional gas reservoirs (UGRs) is currently very important to the energy mix in North America and will be of increasing importance to the global energy industry in the coming decades. Currently, most of the expertise in UGR development resides in the United States. There is a need to make the expertise and technology required to drill, complete and stimulate UGRs more accessible to the engineers outside of North America who need this information. It is also important to capture knowledge and use it for the training of young engineers. To begin addressing these issues, we have developed the UGR Advisor.

We define our advisory system as a detailed, multi-component computer program designed to provide advice, recommendations, and/or best practices for a broad array of issues that arise in developing a UGR. We first begin the process by determining an analog reference basin (or formation to) the target basin (or formation). A reference basin is a basin in North America that produces substantial volumes of unconventional gas and has a large volume of information about the basin in the petroleum or geologic literature. A target basin is the basin that we are currently interested in evaluating or developing.

Once the basin and formation analogs are found, UGR Advisor can be used to obtain advice on how to drill, complete and stimulate the target formation. We have used the petroleum literature to determine best practices and have developed logic to provide advice to the user that is compatible with the published best practices. We have combined knowledge from the petroleum literature and interviews with experts with detailed calculations to build the program, which includes subroutines that evaluate the formation, recommend drilling schedules, suggests completion and production practices, and estimate economics, all from a single-input system for data collection.
Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments
Authors: Denham Waitus , Donadieu Brian , Lee Ernest , Mathur Rohit , Srinivasan Ananth
Published: October 2009

With the world's dependence on hydrocarbon-based energy sources driving global demand, new drilling opportunities require technological innovation to increase efficiencies and optimize production. Some newer drilling operations, particularly in the deepwater arena, involve extreme environments such as ultra-high pressures and demand different approaches to ensure flawless execution. This paper presents the variety of challenges, critical success factors, and lessons learned when drilling these ultra-high pressure wells in the Gulf of Mexico's demanding waters. With downhole pressures approaching 30,000 psi and escalating rig costs, the need for dependable rotary steerable systems (RSS) along with advanced formation evaluation technology is needed now more than ever.

With well depths surpassing 30,000 ft below the mudline and increasing water depths, ultra-high-pressure requirements present a new and challenging frontier for both operators and service companies. These new environments demand advances to existing technologies’ operational limits to endure such pressure extremes, while also accurately positioning the wellbore in the reservoir and obtaining critical geological information as the well is drilled.

A recent example in this pressure regime in the deepwater Gulf of Mexico will be reviewed. In cases, pressure limits of the currently available technology are extended while successfully meeting drilling and evaluation goals. Emphasis is placed on the need for operators and service companies alike to focus on thorough pre-job planning while paying close attention to complete system pressure ratings, high-pressure tool inventory management and detailed reviews. As always, communication is one of the critical success factors to ensure success.

The drilling and evaluation technologies delivered real-time formation pressure and geological information, along with continuous directional control, allowing operators to make vital decisions while drilling. This real-time decision-making capability reduced the time required to execute casing point selection and subsequent sidetrack plans.

Additionally, by following an application-based philosophy to technology selection, critical drilling and evaluation questions were answered in real time, reducing risks for nonproductive time (NPT) in these extreme environments. The case results showcased the ability to set a new performance standard, extend the conventional operating envelope, and deliver answers while drilling.
Coupled 3D Numerical Investigation of Hydraulic Fracture Cleanup for Both Slickwater and Gelled Fluids
Authors: Wills Hector A. , Miskimins Jennifer L. , Kazemi Hossein
Published: October 2009

This paper presents the results a systematic study on fracture cleanup using a two-phase 3-D numerical simulation model specifically developed for this purpose. Previous simulation models consider that the hydraulic fracture is already created and the state of pressure and water saturation around the created fracture (invasion profile) could be replicated by a controlled waterflood. For our work we adopted a different perspective where the invasion profile around the fracture is directly linked to the leakoff of fracture fluid during creation. In other words, a fracture growth model have been linked directly to a finite difference simulator.

All simulations are performed in three stages. First, a fracture creation period is applied, second is a shut-in period and finally, a flowback period. In all these three stages the link to/from the reservoir is through source terms, which varies according to the simulation stage. During fracture creation and shut-in, the created fracture is considered one layer and acts as a boundary condition for the reservoir; then for flow back the fracture is discretized on the z direction to enhance the resolution in the fracture medium. Relative permeability curves for the fracture medium and reservoir medium, are based on real laboratory data. Cases were run for both slickwater and gel-based fracturing fluids.

A base case analysis based on a low permeability sandstone reservoir is shown, followed by sensitivities that include: applied pressure drawdown during production; shut-in time between fracture creation and production; interfacial tension between the gas and aqueous phases; placement of perforations across the entire producing interval versus the upper portion of the reservoir; and different gel concentrations. Results show the pressure drawdown, shut-in times, and perforation placement all have significant effect on fracture face damage and clean-up potential.
Critical Poroviscoelastic Anisotropic Evaluation of Anelastic Strain Recovery Test
Authors: Hoang Son K. , Abousleiman Younane N.
Published: October 2009

The importance of accurate determination of in-situ maximum and minimum horizontal stress orientations and magnitudes can never be over-emphasized in geomechanics-related operations in the oil and gas industry. In this paper, the Anelastic Strain Recovery (ASR) test is revisited, and for the first time, the analytical solution for the relaxation evolution of recovered cores from deep wells is extended to fully cover the poroviscoelastic nature of formation rocks, i.e., viscoelasticity of not only the porous matrix moduli but also the grain bulk modulus, as well as a realistic description of the coring, retrieving, and testing processes, i.e., practical time-dependent stress and pore pressure boundary condition evolution instead of the common Heaviside step unloading used in previous studies. Furthermore, the solution also incorporates material transverse isotropy which is frequently encountered in sedimentary formations yet regularly overlooked in previous works. The study identifies several key parameters for accurate determination of in-situ horizontal stresses from ASR test and serves as a reference for future operations.
Causes of Severe Magnetite Formation During Underbalanced Drilling and Practical Mitigation Strategies
Authors: Ezzat A. M. , Ezell R. G. , Turner J. K. , McNealy R. , Mason S.
Published: October 2009

While drilling underbalanced with potassium chloride (KCl) brine and injected nitrogen generated by a membrane filter, black precipitate and heavy scale deposits on the drillstring were observed. The brine was treated with phosphate ester and an amine-based inhibitor at the optimum pH range to mitigate corrosion. A robust onsite monitoring program of the fluids’ properties and the inhibitor concentration was carried out to help ensure proper control of corrosion during the underbalanced drilling (UBD) operations

Analysis of scale-like deposits scraped off the drillstring was predominantly magnetite with trace amounts of siderite and KCl. Little to no scale was seen on the drillstring below the nitrogen injection point indicating that the injected gasses seemed to be a contributor to the issue.

Examination of the drillstring surfaces beneath these scales and API corrosion rings did not exhibit metal loss or pitting indicating these scales were not consistent with corrosion. Further, scale formation continued to be observed as drilling continued under nil oxygen conditions when cryogenic nitrogen was employed and oxygen levels of less than 1% were maintained. Laboratory and field engineers were deployed to collect samples of the brine used for drilling, the scale deposits, solids recovered at the shale shaker screens, and the fluid returns from the wellbore. The precipitate was mostly amorphous iron oxide with magnetite (i.e., combination of Fe (II) and Fe (III) oxides that is ferrimagnetic in nature).

This paper will present the field and lab data generated which helped in discovering the root cause of the problem and developing practical solutions.
The Systematic Application of Root-Cause Analysis to Failures of Intelligent-Well Completions
Authors: Beyer Eric , Barrilleaux Mark , Hother John , Keates Tom
Published: October 2009

When a producing well fails, the engineering team needs to diagnose the failure quickly, in order to determine the best course of remedial action. This is particularly important with an early-life failure when other wells are still being installed using the same design, raising legitimate concern that the failure may be repeated in those other wells. In practice, diagnosis of a failure when evidence is incomplete, and even inconsistent, can lead to conflicting or incorrect conclusions. A systematic method of root cause analysis forces the discussion to converge on a useful outcome. This paper illustrates how such a method was applied, using a fault-tree structure, to analyze failures in two subsea multizone intelligent completions.

The objectives of the analysis were to -

understand the failures as fully as possible; determine what steps are needed to prevent the failures from recurring on subsequent installations; determine what other tests may be useful to help understand the problem.

The work started by collecting and reviewing the evidence (written reports, and links to knowledgeable people), and defining the symptoms of failure. Then Fault Trees were constructed from all the potential failure modes that fit the symptoms of failure (in this example, 32 in total). These were then used in a structured workshop session to review all those potential failure modes. Those that did not fit the evidence were discarded, in this example leaving just 4 Possible Causes by a process of elimination.

The detailed review of processes and controls required to understand the circumstances of failure was found to be a useful way of identifying improvements to Engineering Processes (documentation control, specification and engineering management) in addition to design and operational issues.

Extra tests were then identified to confirm each Possible Cause, providing further elimination. A structured comparison to find analogues in other similar projects provided further insight. Finally, further characterisation tests and other actions were identified to help avoid future failures. Specific recommended actions (in this example, 32 in total) were identified to address the Possible Causes and so prevent the failures from recurring on subsequent installations.

A FMECA constructed during the well design phase was also consulted to determine any correlation between the failure modes identified therein and the observed failures in the two zones. The conclusions from the FMECA were also examined to identify whether there were any outstanding recommendations or remedial actions.

The study showed that a systematic application of root cause analysis, using fault trees as the underlying structure, can be very effective in focusing engineering effort on resolving the important issues and avoiding time-wasting distractions.
Field Cases: Nonisothermal Behavior Due to Joule-Thomson and Transient Fluid Expansion/Compression Effects
Authors: App J. F.
Published: October 2009

Field cases illustrating nonisothermal behavior due to Joule-Thomson expansion and transient fluid expansion/compression effects are presented in this paper. Nonisothermal effects are particularly noticeable in high drawdown completions due to Joule-Thomson expansion of the reservoir fluids. Depending upon the pressure range and hydrocarbon composition, Joule-Thomson expansion can result in either a heating or cooling effect. At high pressures, Joule-Thomson expansion normally results in an increase in temperature for oil and gas reservoir fluids compared to a temperature reduction for low pressure gas. Field cases of high drawdown completions are presented; the first is a high pressure oil production test in which a temperature increase of 10°F was observed for a 6,000 psi drawdown and the second is a low pressure gas production test in which a temperature reduction of 38°F was recorded for a drawdown of 3,080 psi. The pressure and temperature profiles for each case were simulated with a 1D radial thermal simulator capable of modeling thermal effects due to Joule-Thomson expansion and viscous dissipation. Nonisothermal behavior is also observed after rate changes due to the rate of fluid expansion or compression. These nonisothermal effects, or temperature "jumps", are transient in nature and the direction of the temperature change depends on whether the fluid is expanding or being compressed. The most noticeable illustration of a temperature jump is at the commencement of a buildup. A field case is presented and modeled with a thermal simulator to illustrate this nonisothermal behavior.
Perforator Performance Study Determines Optimum System and Achieves Field Performance Projections
Authors: Rook Melvyn , Haggerty Dennis , Manning Doug , Quattlebaum Clinton
Published: October 2009

The selection of the appropriate perforating gun system provides an essential element of maximizing the potential recovery of an oil or gas field. Perforating guns are often selected with minimal knowledge of the likely downhole charge performance, which commonly includes API 19B Section I test data that evaluates only cement penetration among competing systems. Unfortunately, cement penetration does not always correlate to the penetration in a downhole environment or inflow potential.

A study was recently conducted to evaluate the charge performance in downhole conditions for a gas reservoir in a perforation flow lab (PFL) based on API 19B Section IV1 methods to identify the best performing charge design for a 3-3/8-in. 6 spf gun system. The study evaluated the effects of cement sheath thickness and casing wall material (hard stainless steel vs. carbon steel). The magnitude of pressure in the simulated wellbore was varied to compare slight underbalance with high underbalance to determine the effect of offline perforating limitations. In addition, the separate testing variable of target core diameter was investigated and resulted in a dramatic effect on the perforator performance.

These testing results identified the optimum gun system for use in the Talisman Bunga Orkid gas field. The productivity estimates derived during the charge evaluation were used to validate inflow models, which to date closely match actual production.

An advanced evaluation of perforating systems can provide valuable insight into what is not always intuitive from available published cement penetration data and can be used to further advance production models. The parameters used in the models should be well understood to confidently predict the perforation hole size, penetration, and flow performance.
Identifying Well Completion Applications for Passive Inflow Control Devices
Authors: Garcia Gonzalo A. , Coronado Martin P. , Gavioli Paolo
Published: October 2009

The main horizontal well completion issues have been identified and addressed during the previous decades, resulting in wells with better performance, lower water production and higher recovery efficiencies. One of the most important issues has been inflow equalization, which is affected by reservoir heterogeneities and pressure losses in the completion (annulus and liner). Evaluations of the flow equalization, in sandstone and natural fracture reservoirs, along horizontal wells have shown the importance of this technique to improve reservoir management.

Passive inflow control device (PICD) performance in producer and injector wells under different fluid properties (density and viscosity) and operational conditions will be presented to show the technical benefits of this technique as well as their improved recovery efficiencies when compared to non-PICD completions. The quantification of the benefits of this completion technique was performed using a fully integrated reservoir simulator where the PICD flow performance characteristic, well completion description (packers, blank pipe, gravel pack, annulus flow, etc.), and reservoir simulation are considered.

Lessons learned and best practices regarding equipment selection and specification acquired during the last 10 years are summarized to define potential PICD applications in horizontal wells. Finally, the field experiences and numerical simulation results are analyzed to establish the best well completion strategy to fit specific reservoir conditions.
Modeling Horizontal Completion Deformations in a Deepwater Unconsolidated Sand Reservoir
Authors: Hilbert L. B. , Saraf V. K. , Birbiglia D. K. J. , Shumilak E. E. , Schutjens P. M. T. M. , Hindriks C. O. H. , Klever F. J.
Published: October 2009

We present the development and results of geomechanical models and analyses used to assess the risks of compaction-induced deformation and potential failure of horizontal gravel-pack completions in a field located in deepwater, but at shallow depth below the sea floor. The target reservoir consisted of high-porosity, under-consolidated stacked turbidite sandstones, which are comparable to some of the more well-known, problematic compactive reservoir sands. The formations indicated a high level of risk of depletion-induced compaction, which could produce large deformations and potential failure of completion equipment in horizontal wells. Coupled poroelastoplastic geomechanical finite element models were constructed to assess the risks of completion equipment damage due to depletion-induced reservoir compaction. Both open-hole and cased-hole gravel packed completion configurations were analyzed. Details of the pre-packed screen assembly components were included in the models, such as the ribs between the base pipe and inner screen, and deformable epoxied sand between inner and outer screens. Model results presented in this paper include deformations of the completion equipment and stresses in the screen components, as a function of reservoir depletion pressure. The results of the geomechanical modeling indicated that the overall compaction loading should not cause significant deformation of the specified completion equipment.
Fluid Selection for Energized Hydraulic Fractures
Authors: Friehauf Kyle E. , Sharma Mukul M.
Published: October 2009

Traditional hydraulic fracture simulators do not take into account the compositional, thermal, and phase behavior effects that are crucial to the success of energized fractures. This implies that until recently there has not been a systematic, simulation based approach for energized hydraulic fracture design.

Traditional water-based fracturing fluids are not ideally suited for use in tight, depleted or water sensitive formations. In such situations, if the drawdown pressure does not overcome the capillary forces in the formation, the liquids leaking-off will remain trapped in the invaded zone around the fracture face. A fluid is energized by adding a gas component to the fracturing fluid. Gas addresses the water trapping problem by creating a high gas saturation in the invaded zone, thereby facilitating gas flowback.

In this paper, a fully compositional fracture simulator is used to evaluate different designs for energized fractures. It is shown that gases with high solubility in aqueous solutions perform significantly better than gases that are not. CO2 has higher solubility than N2, and therefore outperforms N2 in most cases. Because N2 is less soluble in water, additional measures are needed to make sure it is present in the invaded zone. This can be done by delaying flowback and allowing the gas phase to penetrate into the invaded zone. Adding methanol to the liquid phase can increase the solubility of CO2 and reduce clay swelling in some formations resulting in more effective fracture treatments.

It is shown that energized fluids should be applied to rocks when the drawdown pressure is insufficient to remove the liquid. This corresponds to a drawdown pressure of ~200 psi for 0.1 md formations, ~500 psi for 0.01 md, and ~1500 psi for 0.001 md.

Simulations show that under a wide range of reservoir conditions, foam qualities from 30 to 50% are optimum because they allow enough gas to saturate the liquid to maximize gas flowback and they yield long fractures. Higher quality (up to 70%) may be necessary if shorter and wider fractures are preferred.

Use of a compositional fracture simulator allows us for the first time to systematically design energized fracture treatments. Simulations provide a cheap and effective method of predicting fracture performance and reaching conclusions that allow the design of better performing fractures.
Wellbore Re-entries and Repairs: Practical Limits of Cementing New Casing Inside Existing Casing
Authors: Metcalf Arthur S. , Purvis Donald L. , Stillwell Shannon
Published: October 2009

Whether a well is being re-entered, after having been abandoned for some time or it simply needs to be repaired to be functional, many operators choose to cement a new smaller outside diameter (OD) casing string inside the old one. Wells previously abandoned have been re-evaluated and found to respond to fracture stimulation using newer methods; however, to accomplish this, the casing string must have integrity. Casing integrity is also of significance to operators in view of state regulations.

The challenges of this type of operation are many. One of these is to avoid excessive surge pressures while running the new casing and means that on many occasions running rates of the casing may have to be approximately 1 foot per second. Excessive surge pressure can fracture a formation of interest, making it difficult to obtain the desired production rates. Another challenge is to match casing size for stimulation with achieving successful cement isolation of an annular space. Smaller diameter casing will result in increased friction pressure and therefore treatment rate restrictions. Stimulation may require multistage completions to be effective. The increased cost of stimulation must be balanced with the need to achieve cement isolation.

Presented are the analyses of various scenarios examining fracture gradient, old casing burst pressures, fracture stimulation rates and pressures and equivalent circulating densities of potential cement slurries. Case histories are used to illustrate these scenarios and present situations in which the cost of the cement pumped versus what should have been required is compared. Also presented, are the operational and cost differences regarding stimulation as a function of casing internal diameter. In one case over three times the quantity cement, which should have been necessary to achieve circulation back to surface, was pumped without circulating.
New Liner-Hanger Technology Improves Safety and Reduces Non-Productive Time in Deviated High-Temperature Wells in South Central Venezuela
Authors: Jimenez Cesar , Soto Simon , Leon Andrehny , Marval Pedro , Schoener-Scott Martin
Published: October 2009

In deep drilling operations, liners hangers are used to eliminate the need to run full strings of casing. Unlike regular casings that are installed back to surface and will be terminated downhole at a hang-off point in the last casing. Depending on the wellbore conditions, deploying liner hangers can be very difficult, and in many scenarios, the bottomhole assembly (BHA) must be rotated and/or reciprocated in order to set the BHA at the target depth. Unfortunately, conventional liner-hanger systems often do not permit tool rotation due to the complex design. Liner-hanger deployment failures can cause loss of the wellbore or a section of the wellbore, which in turn, will result in additional well construction costs to sidetrack and drill another section through the production zone.

An expandable liner hanger that has a less complicated design that withstands aggressive reaming as well as drilling to depth is now available. This expandable system has no external moving parts such as slips, hydraulic-setting cylinders or separate liner-top packers, which are used in conventional liners. These attributes help mitigate the risks associated with the deployment exercise and complexity of the completion.

PDVSA embraced this technology to help them optimize operations in their deep wells in which extreme environments, often close to 300°F, with deviations greater than 60 degrees and setting depths of more that 12,000 feet are encountered.

The benefits that have been gained by adopting this technology are: Optimized capital expenditureOptimized rig-time efficiency (reduced NPT)Avoidance of costly trips to mitigate hanger damage, and premature settingElimination of external moving parts on the hanger assembly (reduced complexity)Reduced rig timeImproved reliability and fluid flowElimination of slip damage to supporting casing

Three case histories that compare the traditional and expandable liner hanger systems and verify the advantages stated above will be presented in the paper.
Optimization of Multiple Hydraulic Fractures for Open Hole Horizontal Wells by Numerical Modeling—Saudi Arabia Case Study
Authors: Lee Byung , Soleimani Arash , Dyer Steve , Bartko Kirk
Published: October 2009

Technological advances in the use of open hole completion with mechanical isolation have led to the ability to perform multiple fracturing applications in one continuous efficient operation. The new system allows effective hydraulic fracture placement by segmenting the lateral with mechanical isolation points using high-performance open hole packers. This application was used successfully in carbonate plays in Saudi Arabia where multiple acid fracture stimulation improved productivity from seven compartments and anisotropic reservoirs with high productivity contrasts.

Optimizing reserve development while maintaining maximum well productivity requires reliable evaluations of stimulation performance for field development planning. Reliable methods include the use of numerical reservoir simulation for the design, in combination with transient analysis techniques for the evaluation of the stimulation solution. In this study, a reservoir simulator incorporating a hydraulic fracture model within a subsurface geological software environment was used to optimize multiple fracturing in an open hole horizontal well in Saudi Arabia. The study investigated the impact of fracture number, location, spacing and geometry on reservoir drainage efficiency by using a sector model with a multisegmented horizontal wellbore model. Comparing various types of reservoirs shows how fracturing design can benefit from understanding the interaction between the reservoir and the horizontal wellbore intersected by hydraulically induced fractures.

An actual reservoir simulation model with geological and structural inputs was used to history match the performance of the fractured well. The same model was also used to interpret the transient pressure buildup data through their flow regimes.
Dynamic Characteristic Evaluation Methods of Stress Sensitive Abnormal High Pressure Gas Reservoir
Authors: Xiao Xiangjiao , Sun Hedong , Han YongXin , Yang JianPing
Published: October 2009

Gas reservoirs with abnormally high pressure have been encountered all over the world. Due to unusual stress environments, a potential impact to reservoir performance is the stress-sensitive permeability. The result of skin factor will be abnormally positive if we interpret the sensitive data using traditional welltesting analysis software. Interpretation of well testing and performance prediction is a major challenge.

This paper establishes a numerical well test model and develops a simulator by finite element method with consideration of stress sensitive permeability. LOG-LOG curves are obtained and their characteristics are analyzed. In the earlier period, the pressure response of sensitive reservoir is identical to that of the normal reservoir. In the latter period, the pressure reservoir reaches a semi-log straight line, but the value of the derivative curve is less than 0.5. The transitional period is controlled by sensitive permeability. For lower permeability module, the transitional period is longer. In the log-log plot, the distance between pressure and pressure derivative is larger than the normal reservoir. Permeability modulus will be obtained by log-log analysis.

An evaluation method of the effect of stress sensitivity on gas deliverability is presented using the concept of permeability modulus. By combining the LIT equation with the material balance equation, the performance prediction model is also established. The tank material balance equation for gas reservoirs has been written taking into account the effective compressibility of formation.

This paper presents an analysis of a flow after flow test in the Tarim abnormally, stress-sensitive gas reservoirs. The effect of stress-sensitive permeability on well test response is analyzed through numerical simulations. Permeability modulus

is about 0.01MPa−1; Skin is −1.48 ( traditional software is 60.8; qAOF decrease is 14%; period of stabilized production decrease is 5.5 a; and, degree of reserve recovery decrease is 6.8%. The interpretation results show that numerical well test analysis can accurately identify gas reservoir parameters and acidizing effectiveness and that the decrease degree of gas deliverability is different and depends on the ‘permeability modulus’ in the formation on which the gas well is located.
Enhanced Migration of Surface-Treated Nanoparticles in Sedimentary Rocks
Authors: Rodriguez Elena , Roberts Matthew R. , Yu Haiyang , Huh Chun , Bryant Steven L.
Published: October 2009

Engineered nanoparticles have properties potentially useful for certain oil recovery processes and formation evaluation. Nanoparticles are small enough to pass through pore throats in typical reservoirs, but they nevertheless can be retained by the rock. The ability to predict retention with distance traveled, and to predict the effect of different surface treatments on retention, is essential for developing field applications of such particles.

We inject concentrated (up to ~20 wt%) aqueous suspensions of surface-treated silica nanoparticles (D = 5 nm and 20 nm) into sedimentary rocks of different lithologies and permeabilities (10−14 to 10−12 m2). The particles generally undergo little ultimate retention, nearly all being eluted by a lengthy postflush. Nevertheless the nanoparticles do not propagate as classical non-retained solutes or particles (e.g. conservative tracers). Effluent nanoparticle concentration histories show breakthroughs later than 1 PV injected, plateau concentrations less than the injected value, and long tails. Longer elution times occur in samples with greater specific surface area. This set of observations is consistent with weak, reversible attachment of particles to pore walls. Such attachment is predicted by DLVO theory for very small particles when van der Waals attraction is the dominant force. This is the situation in our experiments, as the nanoparticles carry virtually no surface charge due to their surface coating.

Compared to viscosities measured on bulk suspensions, the apparent viscosities of suspensions flowing through sedimentary rocks are significantly smaller. Bulk phase viscosities show little or no dependence on shear rate, and all experiments involved single-phase flow in water-wet samples. The simplest explanation for these observations is that a moderately thick layer (several hundred nm) of water depleted of particles exists at the pore walls. The mechanism for depletion of nanoparticles is presumably analogous to the mechanism for depletion of colloidal particles near rough confining surfaces.
Management and Operation of the Colorado School Field: An Interinstitutional Experience Between the Academy and the Industry
Authors: Zuly Calderón C. , Acevedo Duarte Leonardo , Saavedra Nestor Fernando
Published: October 2009

The aim of this paper is to describe the methodology underlying the Project "Colorado School-Field" (Colombia, South America), as well as the monitoring, assessing, and improvement indicators. In addition, it intends to highlight the academic and practical projects designed to improve the conditions of the field, within a medium and long terms. In 2006, this field was given from ECOPETROL S.A. (Colombian Petroleum Company) to the UIS to be operated as a school-field approach which means that it aims both academic and productive objectives and indicators. From the academic point of view, the School-Field involves comprehensively the UIS missionary duties with regard to teaching, research, and community impact. As far as the productive point of view, the activities of exploration, exploitation, and dispatch of crude and gas are reactivated, enhanced and they continuously consider the social responsibility with the community. The experience of the School-Field has been very beneficial for both institutions, as it has reinforced and qualified traditional relationships and agreements between ECOPETROL S.A. and the UIS. The Experience of "Colorado" has also inspired changes in the structure of subject courses in formal and informal education. Now it allows simultaneity of studies, investigation and professional work, convergence of strategic enterprising lines with research lines. In the same way the graduate program subjects must be support and consultancy to improve knowledge products of each posgrade level: research studies in master's programs and doctoral theses. On the other hand, the experience has been an inspiring model to similar projects at UIS such as, turning the Hospital Universitario Regional into a School-Field and supporting (Scientific and Technological Park-Guatigurá, with the presence of both institutions)) other School-Fields in the areas of alternative energy, biotechnology, agro-industry and materials.
The Porochemothermoelastic Coupled Solutions of Stress and Pressure With Applications to Wellbore Stability in Chemically Active Shale
Authors: Nguyen Vinh X. , Abousleiman Younane N.
Published: October 2009

Overcoming wellbore drilling instability in shale formations will always present one of the major challenges to drilling engineers. It is well established that the pore pressure differential between the drilling mud and the drilled formation is governed by the diffusion process which is a time-dependent phenomenon. On the other hand, shales are highly chemically active and they swell when brought in contact with aqueous drilling fluids. Chemical effects arise from imbalance in chemical potentials between the species in the formation pore fluid and wellbore drilling fluid. The transport phenomenon and the diffusive nature of the solvent and solutes in the solution affect the chemical potential, which in turn will modify the fluid pressure, e.g., via chemical osmosis, and eventually may compromise borehole stability. In addition, a temperature gradient between the drilling fluid and the formation will lead to not only induced thermal stresses but also transient thermo-induced pore pressure responses. Thus, the downhole chemical activity and temperature (mud/shale) is also time-dependent variables leading to time delayed failures in collapse or fracture gradient. This work addresses the coupled transient thermal and chemical effects on shale stability through analytical poroelastic inclined wellbore solution. The shale is modeled as an imperfect semi-permeable membrane which can allows partial transport of the solutes. In addition to chemical osmosis, both solute transport and thermal effects are taken into account to realistically model field condition. The solution is applicable to studying deep shale drilling using water based mud where thermal effect and chemical interaction are significant. The solution is helpful in the prediction and visualization of time-dependent alteration of near wellbore effective stress concentration as well as mud chemistry, density and temperature effects on the mudweight window. Specifically, borehole stability is investigated under various scenarios such as heating, cooling, high and low mud activity for simulated downhole condition as well as for a field case. Analyses reveal that cooling the wellbore and high mud activity can destabilize the near wellbore region and result in a narrower mudweight window. Ignoring the coupled solute transport and thermal effect may mislead the optimization of mud density, mud salinity or mud temperature to stabilize the wellbore over the course of time.