bluuebunny/crossref_metadata_2025 huggingface dataset:
Increasing Lateral Coverage in Eagle Ford Horizontal Shale Completion
Authors: Nwabuoku Kennedy Chukwuemeka
Published: October 2011

Abstract A major challenge to efficiently developing a horizontal completion in shale is knowing what spacing and how many perforation clusters per stage will be optimal in effectively draining the reservoir. One of the major questions in developing the Eagle Ford shale was what spacing and lateral coverage will be optimal. A search for a case study revealed that no scientific study has addressed this concern. Industry practice has been based largely on available capital or best estimations. Hence the plan starting out was to carry out a case study of different lateral spacing and different perforation clusters per stage. The Eagle Ford shale play in South Texas is, in terms of development, in its infancy compared to other shale plays in North America. The Barnett shale, for example, has been commercially productive for over 15 years now, and the Haynesville shale has been commercially productive for over five years, whereas completion and commercial production of Eagle Ford is less than two years. Thus, there is the tendency to apply the methodology used in the older shale plays to Eagle Ford, which has different formation characteristics and mineralogy content. The first wells were completed in Eagle Ford with the typical 4,000 ft lateral length, four perforation clusters, and 300,000 - 350,000 lb of proppant per stage with a total of 16 stages. Radioactive tracers (antimony, scandium, and iridium) were used to tag the proppant, chemical tracers to mark the stage frac fluid, flow-through composite bridge plug was used to isolate the treated zone. After stimulating all the zones, plugs were drilled out and a Spectrascan tool was run in hole with coil tubing to log the lateral zone. Results from the tracer log on the first well show that most of the perforated zones were treated with the exception of the toe stage, which showed little or no stimulation. A close observation of the tracer log output shows that the treated lateral area (the area with tracer signature) was less than half of the entire lateral length. A linear count of the exact lateral length covered by the tracer mark compared to the entire lateral length revealed less than 36% coverage. This paper focuses on the changes that were made to the completion methodology in an effort to improve the stimulated lateral coverage, the effect of those changes on reservoir performance and improvement in the well productivity index. Details of the 100% improvement in stimulated lateral coverage that was obtained and the effect on productivity index are outlined in this paper. Introduction The Eagle Ford shale lies above the Buda limestone and is itself non-conformably overlain by the Austin chalk. Fig. 1 shows a stratigraphic column through Eagle Ford in South Texas. This cretaceous shale formation occurs over a laterally extensive area from Dimmit County in the west across the state to the eastern county of Lavaca and beyond.
Integrated Field Optimization Strategy Applied to an Offshore Water Injection Project
Authors: Chaban F. R. , Jordan L. C. , Annadorai K. M. , Wilkinson T. W. , Myers P.
Published: October 2011

Some of the most significant challenges faced with respect to the management of offshore water injection projects are associated with maintaining injectivity into the reservoir and with handling H2S produced due to reservoir souring. This paper presents the process followed and findings generated by a comprehensive review of a mature water injection project performed with the goal of delivering a coordinated operating strategy that would maximize the life of field revenues associated with water injection.

An integrated and comprehensive field optimization approach to maximize the whole-life value of the total asset was undertaken. Aspects covered included water injection system operating practices, mechanical design and integrity management of the injection system, the chemical treatment program followed for both the injection and production streams, and reservoir modeling and production management.

Recommendations resulting from this review were prioritized based on their impact on the whole-life performance of the asset, rather than the more common practice of separating the injection and production system reviews or the assessments of reservoir management and facility operation. Areas of particular benefit were identified in association with implementation of an active souring control strategy to reduce future risks to the production system metallurgy by sulfide stress cracking (SSC), a focus on integrity management of the water injection system to maximize long-term system availability, and the implementation of an inter-well water tracer injection program to enable the validation of current reservoir models and support the placement of future injectors and producers.

The combined approach employed in this review has enabled the Operator to adopt an operating strategy for the facility that will optimize operating costs and revenues through the remaining life of the asset. In addition to gains in future injection system uptime and the immediate optimization of the chemical treatment program, this review has also provided a basis to guide the evaluation of future reservoir management and field development strategies.
Application & Evolution of Formation Pressure While Drilling Technology (FPWD) Applied To The Gulf of Mexico
Authors: Blanco Yon , Turner Marcus
Published: October 2011

The emergence of formation pressure while drilling (FPWD) technology into the Gulf of Mexico (GoM) in 2004 was a step change for the industry. Over time the technology has been accepted by the industry as a reliable source for formation pressure and mobility measurements in real time for both reservoir evaluation and drilling optimisation. As the drilling frontiers are pushed, FPWD technology has advanced to meet the challenges. What have we learnt from this journey?

Today, the technology is applied in an increasingly diverse environment in the GoM with a focus on safety and data quality. This has been achieved by a perpetual learning and development cycle, advancing FPWD technology, logging while drilling (LWD) technology and refining processes. Advances in Real Time capabilities in LWD have also become critical to allow fast and founded decisions.

Examples are presented reviewing the applications and associated development of the technology over time to meet and exceed the GoM challenges:

Ultra deepwater, high pressure exploration in pressures exceeding 27k psi Reservoir evaluation in the heterogeneous Wilcox formation, where mobilities can swing from 0.5 to 50 mD/cP in a matter of inches, result in poor quality or long stationary times when fixed rates and volumes are applied blindly; however integration of a intelligent pretest design that automatically determines optimal rates and volumes in milliseconds can turn failure into success Sub salt drilling optimisation and pore pressure calibration Testing in severe pore pressure regression and/or highly depleted reservoirs with overbalances in excess of 7k psi. Refining electronics and pretest motor controls opened up new opportunities for operators to determine magnitudes of depletion previously unobtainable Shallow, unconsolidated or highly overpressured formations, which can lead to lost seals as the effective stress increase to the point of sand face failure, unique test designs perform low shock tests against the formation Well to well comparisons for vertical and lateral connectivity required pressure gauge development in high pressure environments >20k psi

High spread rates in deepwater GoM require the efficient application of these new technologies. Through application of lessons learnt and technology advancements, Non Productive Time (NPT) can be minimized and data quality maximized.
Wellbore Cleanup Tools Save Rig Time in Approximately 30% Optimizing Workover and Completion Operations
Authors: Cárdenas Jorge Luis , Rueda Ana , Guerra Edmundo , Vera Juan
Published: October 2011

During workover and well completion operations several sub-events are performed to put a well back on production or to start production on a new well. These events are carefully planned considering people, environment, reservoir, wellbore integrity, well productivity and final cost of workover and Completion.

In the oil business optimizing production costs is the way to go when a project is conducted with financial based criteria, but thinking about maximizing well productivity and avoiding deferred production is also important when a project is being planned.

Conventional wellbore cleanup practices are often used in the industry but sometimes this process is not considered as an important part of the operations. Common problems associated to oil production that may reduce the well productivity like inorganic scale, sand, corrosion, paraffin and asphaltenes can be removed with specific wellbore cleanup tools and techniques. The time associated to clean up a well represents 40% up to 60% of the total workover time using conventional cleaning tools.

Continuous process improvement and risk management has helped to use an alternative method that improved cleaning process reducing time and all the associated costs, this method includes the use of new technology on non rotating tools (scrappers and brushes), magnets, filters and sand recovery tools.

Additional benefits are also obtained using this new technology, such as minimizing non-productive time, reduction of formation damage due to workover fluids and rock interaction, improvement of ESPs run life among others.

This paper describes how changing the wellbore cleanup methods and the use of appropriate tools had permitted to reduce rig time in about 30% when a well is being intervened. The study includes information of one year using wellbore cleanup tools in more than 70 wells in Tarapoa onshore Field located in Ecuador. Significant cost reduction and anticipated oil production demonstrate that this method can be economically applied.
Shale Oil Production Performance from a Stimulated Reservoir Volume
Authors: Chaudhary Anish Singh , Ehlig-Economides Christine , Wattenbarger Robert
Published: October 2011

The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is limited to lower recovery efficiency than shale gas. However, the recently discovered Eagle Ford formations is significantly overpressured, and initial formation pressures is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional oil formations.

Relative permeability behavior, including the critical gas saturation, is likely to be quite different in created fractures from that of the shale matrix, and technology for laboratory multiphase flow measurements has not been developed for such low absolute permeability values as are found in shale formations. Further, propent embedment and expected multi-phase flow in the created hydraulic fractures can lead to actual values of fracture conductivity in the created fractures order of magnitude lower than the values reported in the laboratory.

As with shale gas, high recovery in shale oil wells will require that created hydraulic fractures are spaced close enough to result in interfracture interference during the time the well is on production. This study investigates the role of the fracture spacing, fracture conductivity, fracture half-length, critical gas saturation, flowing bottom-hole pressure and matrix permeability in the well economics and the ultimate recovery efficiency considering flow both above and below the bubble point pressure and using known properties of successful shale oil plays. Simulations show that results are strongly dependent on assumed relative permeability behavior, and sensitivity studies provide considerable insight about the long term production behavior than can be expected in these wells.
A New Coiled Tubing Application to Enhance Operating Envelope for Deepwater Production
Authors: Dong Hongkun , Shi Hua , Norris Lee , Berger Ron
Published: October 2011

The objectives of this study were to investigate the effects of coiled tubing size, flow path, gas lift and water cut on the onset of severe slugging and overall operating envelope. The coiled tubing was investigated as a technique for delaying the onset of slugging, which involved the use of larger diameter coiled tubing strings to decrease the flowing area in the annulus, or routing the flow up within coiled tubing instead of annulus to flow directly in coiled tubing. The operating envelope considering slugging and other system constraints was also investigated with the use of coiled tubing. The minimum nonslugging rate was reduced by using larger coiled tubing size with normal flow through annulus. A very low non-slugging rate was achieved with small diameter coiled tubing when producing through the coiled tubing, but a very narrow operation window was left when other system constraints were considered. The minimum non-slugging rate increased rapidly as the coiled tubing size increased when flowing within coiled tubing. Gas lift was effective in reducing the minimum non-slugging rate when it was increased from 0 to 4 mmscfd, but not very effective in one of the risers when it was further increased from 4 to 8 mmscfd. Increase of water cut appeared not to have a significant effect on the minimum non slugging rate.

The study explored a new way of coiled tubing application in production design. It provides a guidance of how to effectively use coiled tubing as a technique to reduce the minimum non slugging rate, especially the flow through either annular or within coiled tubing. The field life can be extensively extended with a proper selection coiled tubing size, flow path and gas lift. A workflow of coiled tubing size selection and operating window determination considering different system constraints was also demonstrated.
Water As Proppant
Authors: Ehlig-Economides Christine A. , Economides Michael J.
Published: October 2011

The horizontal well with multiple transverse fractures, has proven to be a successful approach for production of gas from shale. As many as 80 fractures and nearly 10 million gallons of fracture fluid have been employed in a single well. However, unlike for conventional hydraulic fractures, in shale gas wells most of the treatment water never flows back.

In this paper we postulate that the water has actually stayed in the created fractures and/or in enhanced natural fractures. The reason why fractures exhibit high conductivity flow behavior even with very little proppant is because the water injected in the fractures cannot leak off into the shale matrix, and relative permeability in the fracture impairs the water from flowing back. Water remaining in the fractures actually prevents them from closing. Gas bubbles or channels to the horizontal borehole through water in the fractures.

In shale gas formations some diagnostic fluid injection tests appear to never exhibit closure or close with indicated fluid efficiency of 90% or more. In the period during execution and before flow back, water is too viscous for the large fluid volumes injected to flow into the extremely low permeability shale matrix. If treatment water could leak off, unpropped fractures in shale would likely close. Because the gas is water-saturated as it enters the water filled fracture, there is little tendency to vaporize the water. Therefore, water as proppant resolves both the question why so much treatment water never flows back and why fracture complexity can remain open indefinitely without proppant slurry.
Characterization of Well Performance in Unconventional Reservoirs using Production Data Diagnostics
Authors: Ilk D. , Okouma V. , Blasingame T. A.
Published: October 2011

Production analysis and forecast in unconventional reservoirs are challenging tasks due to high degree of uncertainty and non-uniqueness associated with well/reservoir properties. At this point the importance of diagnosis of production data to check the data consistency and to identify flow regimes has become significant. In addition, we believe that producing wells in various unconventional reservoirs exhibit unique production performance behavior due to geology, phase behavior, and completion practices. Therefore, the identification of the related performance behavior is crucial for development and forecast purposes.

The primary objective of this work is to apply diagnostic methods to investigate and understand production performance characteristics of the wells producing in unconventional reservoir systems. For our purposes, we present examples from various shale gas plays.

We propose the use of various forms of rate-time and rate-time-pressure plots for production data diagnostics. In particular, this work presents the utilization of the dimensionless βq,cp-derivative formulation (i.e., logarithmic derivative of the rate function with respect to logarithm of time) to identify production behavior characteristics. We also propose the use of several diagnostic plots to identify performance characteristics and data consistency. In addition the use of average rate functions are presented for better resolution.
Accurate Measurement, Correlation and Simulation of Multi-component BTEX Solubility in Amine Solutions
Authors: Borda R. T. , Civan F.
Published: October 2011

The accurate prediction of BTEX solubility in natural gas conditioning processes is of major importance since the monitoring of the emissions of these contaminants to the atmosphere depends on this knowledge. This paper presents experimental solubility data of a multi-component gas composed by Methane, Benzene, Toluene, Ethylbenzene and p-Xylene into MDEA solutions. The gas-liquid system used in this work represents a realistic experimental environment. The synthetic multicomponent gas used in the experiments has similar BTEX content than that of a real gas processing plant. A material balance method is used to obtain accurate solubility results. Gas chromatography (GC) analysis is performed to determine the solubility of the BTEX compounds of the multi-component gas. Experimental data is analyzed, correlated and compared to literature and commercial software results. The results from all the sources is discussed and compared side by side.
Multidisciplinary Team Implementation: A Step Beyond Integration
Authors: Battalora L. A. , Curtis J. B. , Davis T. L. , Miller M. G. , Smith B. W. , Sonnenberg S. A
Published: October 2011

An educational model exists at the Colorado School of Mines (CSM) that responds to current industry objectives, incorporates the SPE Professional Competency Matrices1 (hereinafter, Competency Matrices) and satisfies the Accreditation Board of Engineering and Technology (ABET)2 requirements. GEGN/GPGN/PEGN439 Multidisciplinary Petroleum Design (hereinafter, 439 Capstone Course) is the cross-discipline, senior-level, capstone design course in the Geological Engineering, Geophysical Engineering and Petroleum Engineering Departments. Historically, the 439 Capstone Course has met ABET requirements and industry objectives by providing students with multidisciplinary problem solving and integrated team experience prior to entering the work force. Teamwork experiences focused on the integration of data, information, and people from the disciplines of geology, geophysics, and petroleum engineering. However, the need exists to move beyond "integration" with a step forward to "implementation." Using the Competency Matrices as a guideline and responding to industry feedback, the revised 439 Capstone Course is a novel educational approach that accomplishes this goal.
Well Evolution in the James Lime: How Technology has Driven Well Productivity Improvements
Authors: Baihly Jason , Altman Raphael , Aviles Isaac , Seale Rocky , Snyder D J
Published: October 2011

The James Lime is a carbonate formation located along the United States Gulf of Mexico upper coast. Exploration wells were drilled in the James Lime beginning in the 1950's, with commercial activity occurring in the following decade. Wells were drilled exclusively vertical from its discovery through the late 1990's. Over this timeframe, these wells had a great deal of variability in production which hindered the development of the play. Given the apparent rock potential, the production results from these types of completions were oftentimes disappointing and uneconomical.

Many different types of drilling and completion technologies have been attempted over the history of the James Lime in order to improve production results. Little has been publicly documented on the impact of these step changes attempted on the James Lime. One striking technological innovation occurred in the late 1990's when operators started drilling wells horizontally in the James Lime. Initially these wells were either not stimulated or completed with a single stage hydraulic fracturing treatment. Just drilling horizontally had little impact on production results and consistency. Within a few years of horizontal development, wells started to be hydraulically fractured with multiple treatment stages using advanced open-hole multistage isolation systems. These two technological innovations along with others had an impact on increasing James Lime production over time. (IHS, 2011)

This paper analyzes the various drilling and completion technologies that have been applied to the James Lime over its 50 year history. The impact on production of these practices since 1995 is also presented. Some of the variants analyzed to determine their impact on production include hole direction, lateral length, completion isolation system, and number of stages treated. Hydraulic fracturing treatment details such as proppant type, treatment volume, and proppant volume were analyzed to determine their impact on production results as well. Other factors were taken into consideration when performing the production analysis including the timeframe when the well was drilled and completed.

The results of this analysis uncovered the impact on production that technological advancements had over time on the tight James Lime carbonate formation. It highlights the key production drivers in the James Lime and how to improve production of future wells drilled in the formation. Furthermore, the lessons learned and key technologies from this formation can be applied to other tight carbonate plays around the world.
Optimal Fracture Spacing and Stimulation Design for Horizontal Wells in Unconventional Gas Reservoirs
Authors: Bhattacharya Srimoyee , Nikolaou Michael
Published: October 2011

Hydraulic fracturing of horizontal wells is crucial for economic production of natural gas from unconventional reservoirs. For transverse fractures, existing approaches for making decisions on fracture spacing and length are based on sensitivity analysis using reservoir and/or fracture propagation simulators. The use of commercial simulators relies on assessment of various what-if scenarios, which are set up based on experience and data collected from completed wells in the same or similar reservoirs. Because of the large number of possible decision variables, the decision-making process is complex, potentially leading to non-optimal. A computer-aided tool that could facilitate the process would allow engineers to efficiently converge to solutions that are at or close to the optimum.

The proposed approach relies on a novel efficient numerical optimization tool. The optimization objective function is Net Present Value (NPV) for horizontal wells drilled in the direction of the minimum horizontal stress, which allows multiple transverse fractures. Key decision variables are number of transverse fractures in a horizontal well; horizontal well length; proppant concentration; injection rate of fracturing fluid; injection time; fluid performance index and fluid consistency index. Key design constraints are fracture growth control, and geometric constraints. To set up the optimization, critical reservoir properties are assumed to be available from a variety of sources (e.g., seismic, prior production logs). The modified PKN model along with Carter's Equation for material balance is used for hydraulic fracturing propagation where fracture width, half length and net pressure are calculated. Productivity of multiple fractured horizontal wells is computed by using analytical equations. A robust optimization algorithm is used for finding the optimum parameters.

The capability and robustness of the proposed approach is demonstrated for a tight gas reservoir for which horizontal well geometry and its fracturing treatment is designed based on numerical simulations. A commercial simulator served as virtual reservoir with properties calibrated based on SPE case studies. The simulation show optimization can significantly increase NPV over other available solutions. Sensitivity analysis is done on various decision variables to show their significance in decision making for well stimulation. Also, significance of choosing optimum number of operating years is discussed in order to avoid missing optimum recovery. It is shown how important it is to find the optimum number of years for a particular formation which can give the maximum profit.

The proposed tool can provide a quantitative assessment of optimal horizontal well stimulations. It is envisioned to be used in an integrated decision support system that will help engineers to use a multitude of available data for development of unconventional gas resources.
Estimated Ultimate Recovery (EUR) as a Function of Production Practices in the Haynesville Shale
Authors: Okouma V. , Guillot F. , Sarfare M. , Sen V. , Ilk D. , Blasingame T. A.
Published: October 2011

Recent developments in well completion technologies have transformed the unconventional reservoir systems into economically feasible reservoirs. However, the uncertainty associated with production forecasts and non-uniqueness related with well/reservoir parameter estimation, are the main issues in future development of these reservoirs. In addition, recent operational methods such as restricting rates by decreasing the choke size add up to the uncertainty in production forecasts.

This work attempts to investigate the effect of production practices on ultimate recovery. It is observed that wells producing in the Haynesville shale gas play exhibit severe productivity loss throughout their producing life. Production practices such as controlling the drawdown or restricting rates by decreasing the choke size are employed by several operators to deal with the severe productivity loss. In this work our main objective is to investigate the issues (such as stress dependent permeability, proppant embedment, operational problems, etc.) contributing to decreasing well productivity over time. In particular, from modeling standpoint, we focus on stress-dependent permeability as a mechanism, which affects well performance over time.

Using a horizontal well with multiple fractures numerical simulation model coupled with geomechanics, we generate synthetic simulation cases including several drawdown scenarios. It is shown that high drawdown cases result in higher effective stress fields around the well and fracture system. We therefore infer that higher effective stress fields result in lower well productivity over time. Based on this hypothesis and diagnostics of field data, we model two different scenarios (i.e., high drawdown and low drawdown cases) for a horizontal well with multiple fractures using two different permeability decay functions and same well/formation model parameters. Our modelling results indicate that low drawdown case yields higher recovery suggesting that rate restriction could be a mitigating factor in decreasing well productivity over time.
Experimental and Field Data Analyses of Ball Sealer Diversion
Authors: Nozaki M. , Zhu D. , Hill A. D.
Published: October 2011

Diversion methods are routinely used in both matrix acidizing and fracturing stimulation treatments. The diversion methods are categorized into chemical diversion and mechanical diversion. In this study, we focus on one of the classical mechanical diversion methods, ball sealers. Ball sealer diversion is used in cased and perforated wells to divert stimulation fluids by temporarily blocking perforation holes in the casing with rubber-coated balls. This diversion method can be very effective, particularly with high rate injection, but no general methodology is available to design ball sealer diversion, or to evaluate its effectiveness from the treating rate and pressure record.

Although some design methodologies, such as the use of buoyant ball sealers to improve the ball sealer efficiency, have been suggested, no model has been presented for determining how many balls seat on the perforations. In this paper, experimental data from an extensive series of full-scale flow experiments conducted by BP were analyzed. We summarized several features of the ball sealer which are not presented in the literature. Also we used the procedure presented by Brown et al. (1963) to evaluate statistical nature of the ball behavior in the BP's experimental results. The BP experiments were designed to minimize scatter of data. However, the seating process was found to be statistical.

Also we analyzed one field acid fracturing treatment where ball sealers were used as a diversion method. Then the analyzed data were compared to the BP experimental results. A similar trend in seating efficiency was observed.
Toward Quantitative Remaining Oil Saturation (ROS): Determination Challenges and Techniques
Authors: Al-Harbi Ahmed , Schmitt Denis P. , Ma Shouxiang M.
Published: October 2011

Remaining Oil Saturation (ROS) is a crucial input to reservoir development projects. Determination of such a time-dependent parameter assists the evaluation of the sweep efficiency, provides calibration points for simulation models and also sets the basis for future workover and EOR projects.

Quantification of ROS in waterflooded areas has always been a known challenge to resistivity-based techniques. The mixed water salinity environment, due to differences between original connate water and injected water, and the impact of the imbibition process on the saturation exponents are the main hindrances.

Over the past few years, data acquisition strategies have been deployed to overcome these challenges. The strategies include in-situ measurements that are insensitive to water salinity and to fluid displacement processes, such as Nuclear Magnetic Resonance in Log-Inject-Log mode, Carbon/Oxygen, and Dielectric logs. Extensive wireline formation testing programs usually follow to confirm the findings from the aforementioned measurements. Depending on the well's criticality, special coring programs might also be included such as sponge coring or liquid trapper. Special planning and standardization efforts are necessary for such extensive data acquisition programs to ensure data quality and consistency.

This paper presents Saudi Aramco data acquisition strategies for ROS applications. It also highlights the main challenges and the technologies deployed to resolve them. Advantages and limitations of these technologies are reviewed. Lastly, our ongoing efforts to reduce the uncertainties of such analyses are presented.
An Experimental Investigation of Spontaneous Imbibition in Gas Shales
Authors: Roychaudhuri B. , Tsotsis T. , Jessen K.
Published: October 2011

Multi-stage horizontal wells play an important role in the development of domestic shale-gas resources. The completion strategy for shale-gas wells commonly includes hydraulic fracturing that utilizes large volumes of fresh (and recycled water) complimented by the addition of assorted chemicals. A general observation from the completion of shale-gas wells is that a large fraction of the injected water remains in the formation after flowback, and that the fluid loss from any single well can exceed 50% of the original injected volume. In this work, we study spontaneous imbibition of water into shale samples from the Appalachian Basin in order to explore the role of capillarity in the fluid-loss mechanism. We investigate the imbibition characteristics for a range of shale samples encompassing the mineralogy and petrophysical properties that can be observed along the vertical column of a gas play.

Imbibition experiments are performed on shale cubes, whereby one face of the sample is exposed to water in order to mimic the invasion characteristics of the fracturing fluid from the main hydraulic fracture through the micro-fracture network into the shale matrix. In most of the experiments we observe a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. This transition is attributed to the complex, multi-porosity nature of the shale samples which are characterized by a micro-fracture network imbedded in the sample matrix. Based on a scaling argument, we demonstrate that the fluid loss during hydraulic fracturing can be explained, at least in part, by the imbibition processes.
Validation Process for Human Factor in Complex Upstream Oil and Gas Operations
Authors: Ershaghi Iraj , Luna Dennis R.
Published: October 2011

During drilling, completion and production operations, engineers and work crew often encounter critical situations requiring rapid decision making with insufficient information about their root causes while facing unknown consequences. Of concern is their experience and training to handle crisis management and in meeting the appropriate standards of care for the health and welfare of the workers and as well as their social and business responsibilities. The petroleum industry has been keen to exercise and mandate zero tolerance in oilfield accidents. Major operators, most large size independent and national oil companies have each adopted in-house standards and certification of their engineers and workers. In spite of these efforts, the industry continues to receive criticism when it comes to human and environmental safety issues. The nature of oil industry is becoming such that one act of mishandling of a crisis situation by any size company can have a drastic impact on the entire industry. We discuss the necessity of step changes in adopting universal standards for validation of the experience and training to successfully manage a crisis situation using advances in Information Technology as a means of enhancing trustworthiness of global upstream operations.
Practical Aspects of In-situ Ball Seat Milling
Authors: Halvorsen Helge , Arnskov Michael Macdonald
Published: October 2011

A ball seat placed deeply in one of the wells in the North Continental Shelf (NCS) had to be removed as part of a reconfiguration work-over. To achieve this, a milling operation scheme was devised. As this was the first time a ball seat of this type had to be removed by milling in the NCS the operation was rehearsed and evaluated onshore.

An identical setup with two sizes of seats and balls was established in an almost horizontal pipe setup onshore and the toolstring consisting of a conveyance tractor mounted with a milling device fitted with a tungsten carbide bit was driven into the pipe. The milling was carried out with different levels of weight on bit by adding back-tension on the cable as well as using different numbers of drive sections on the tractor. Then the results were evaluated. Additional tests were carried out with parts of a milled ball dropped down hole on the ball seat to ensure that milling could be done. The tests showed that the tool-string as configured could mill out the ball seats in one operation. This was later confirmed as the actual seat situated at 12.647 ft. measured depth was removed in one run. The paper provides a detailed account of the preparations and actual milling operation, including the lessons learned and how the objectives were achieved.
A Workflow Concept To Characterize Core Samples From The Microscale To The Nanoscale
Authors: Lemmens Herman , Butcher Alan
Published: October 2011

Increased interest in shale and tight gas reservoir characterization has sparked the adoption of novel techniques to go down to the nanometer scale. Typically, the smaller the features of interest are that can be resolved, the smaller the field of view becomes. This inevitably leads to concerns about representativity and upscaling.

Estimating reservoir quality in gas shale for example requires a good understanding of pore structure and pore connectivity. Gas shales are known to contain finely-dispersed porous organic matter within an inorganic matrix. The porosity within the organic phase has pore and pore throat dimensions typically below 100 nanometers and even down to just a few nanometers. For direct visualization of the pore network, FIB/SEM is the only technology with nanometer resolution in three dimensions. Field of view typically is only 10 to 20 microns.

Mineral characterization at the micron scale by Automated Petrography based on SEM/EDX analysis can image the full core surface; but lacks the resolution to visualize the small pores. Large area imaging creates images the size of the EDX maps but with the resolution used in the FIB/SEM dataset. Smart choice of the FIB/SEM location can be done on these images to obtain statistically relevant 3D datasets.

An example is presented of a piece of Marcellus shale imaged at different length scales.
Analysis of Transient Well Tests Affected by Wellbore Storage, Skin, and Short Injection/Production Time
Authors: Fuentes-Cruz Gorgonio , Camacho-Velázquez Rodolfo , Vásquez-Cruz Mario
Published: October 2011

The well test analysis techniques of falloff and buildup tests usually assume that at the end of the period of injection or production, the wellbore storage effect is negligible; nevertheless, this assumption is not always valid in impulse tests due to the short duration of the flow time. This situation is important in low mobility reservoirs, where the wellbore storage effects may last hours or days.

In this work, impulse tests are studied for the cases in which the period of injection/production is dominated by the wellbore storage effect. New equations are presented and it is demonstrated that the conventional expressions, existing for decades in the technical literature, must be modified since it is not feasible to apply them under these operational conditions.

Based on the results presented in this work it is concluded that in general, the pressure response of the unit slope period observed at early shut-in times, depends not only on wellbore storage coefficient and rate, but also on the formation transmissibility, skin factor, injection/production time, and the parameters that intervene in the definition of the dimensionless wellbore storage coefficient. In addition, guidelines are proposed for the impulse tests analysis, which combine the use of the shut-in pressure change, the superposition time pressure derivative, and the second drawdown derivative response.

With the aim to illustrate the validity of the new approximations, several cases of tests with short time of injection/production are shown, in such a way that it is possible to identify situations for which the classical expressions of well test analysis are not valid and must be substituted by the equations introduced in this work.
Stimulating a Barefoot Completion with Multiple Sand Fracture Treatments Using an Inflatable Packer Straddle System
Authors: Campbell C. , Brooks R. T. , Davis T.
Published: October 2011

A new method to create multiple fractures in a barefoot completion with a sand fracture treatment has been successfully deployed in Canada. This new method, utilizing an inflatable packer straddle system, has allowed all potential pay intervals to be effectively stimulated, as compared with traditional methods. This new approach of stimulating the open hole, without having permanent packers and frac sleeves or a cemented liner has resulted in reduced completion costs and improved production results.

In an effort to effectively, efficiently, and affordably stimulate these wells proven technology was modified to perform sand fracture treatments without depending on a liner. The system can be deployed on jointed pipe or coil tubing. The Bakken Formation in Southeast Saskatchewan and Southwest Manitoba was a prime candidate for trial testing due to the low treatment pressures and sand volumes.

Most recently the two typical completion methods in the Canadian Bakken use either open hole mechanical packers with ball activated frac sleeves, or cemented liner and hydrajet perforations placing the fracture treatment with coil tubing.

One of the primary concerns about the conventional liner methods is assurance of knowing where the fracture is being placed. There is no way to determine that there was adequate annular isolation to ensure where any of the planned fracture treatments were placed. Using a straddle system with a five meter (16.4 feet) interval allows the operator to know exactly where the fracture was placed in the reservoir.

Knowing the location of the fracture can provide clarity when analyzing production results. Producing as a barefoot completion may add incremental production from naturally fractured intervals that otherwise would have been sealed off with cement. Additionally, a barefoot completion provides flexibility for interventions or adding additional laterals since there is no liner that creates a restriction.

Main considerations of how the tool was developed to resist erosion and how the tool operates will be discussed. Case histories will be presented highlighting the job procedure as well as the economic advantage of using the inflatable packer straddle system. Reductions in completion and stimulation costs of 40% less than a liner completion have been achieved.
Practical Justification for an Empirical Approach to Probabilistic Undeveloped Reserve Bookings In Resource Plays
Authors: Dobson M. L. , Lupardus P. D. , Lee W. John
Published: October 2011

This paper is the third paper in a three part series which collectively presents a new practical method for probabilistic reserve evaluation under the recently released Modernization of Oil and Gas Reporting Rules by the Securities and Exchange Commission (SEC) (SEC 2009). This paper is focused on a methodology to validate the new stochastic booking method outlined in the first two papers of the series. When major changes are contemplated for key systems within a company it is critical to evaluate those changes prior to implementation. Moving to a new method of reserve evaluation and reporting could potentially have major implications for almost any oil and gas company. Internal uses of the reserve report as well as legal requirements of disclosure to regulatory agencies and governing bodies elevates the need to understand the scope of the modifications before they are adopted.

This paper presents an approach wherein the evaluator can test the proposed probabilistic methods against the actual field data. The test is used to predict the repeatability and reliability of the results. In essence, it applies an empirical approach to insure the technique meets the SEC requirement to be considered a reliable technology. When this approach is conducted over independent units of time and distinct spatial areas the repeatability of the answers supports the robustness and confidence needed to meet the requirements of the Modernized Rules.

Theoretical Proved Undeveloped (PUD) bookings were created using the new stochastic method for specific locations for a prior time period; those results were compared to actual post production proved developed producing (PDP) well estimated ultimate recovery (EUR) results for the same locations. Results for a specific case history are presented. The PDP results are in aggregate slightly greater than the aggregated PUD bookings. The new method constitutes a reliable technology and this paper outlines an approach to test the method prior to implementation in a company's work flow.
Theoretical and Experimental Modeling of Residual Gel Filter Cake Displacement in Propped Fractures
Authors: Ouyang Liangchen , Yango Takwe , Zhu D. , Hill A. D.
Published: October 2011

Fracture fluid damage caused by residual polymer gel in propped fractures results in low fracture conductivity and short effective fracture length, sometimes severely reducing the productivity of a hydraulically fractured well. The residual gels are concentrated in the filter cakes built on the fracture walls and have much higher polymer concentration than the original gel. The residual gel exhibits a higher yield stress, and is difficult to remove after fracture closure.

In this work we studied polymer gel behavior in hydraulic fracturing theoretically and experimentally. We developed a model to describe the flow behavior of residual polymer gel being displaced by gas in parallel plates. We developed analytical models for gas-liquid two-phase stratified flow of Newtonian gas and non-Newtonian residual gel to investigate gel cleanup under different conditions. The concentrated gel in the filter cake was modeled as a Herschel-Buckley fluid, a shear-thinning fluid following a power law relationship, but also having a yield stress.

The model developed shows that three flow regimes may exist in a slot, depending on the gas flow rate and the filter cake yield stress. At low gas velocities, the filter cake will be completely immobile. At higher gas velocity, the shear at the fracture wall exceeds the yield stress of the filter cake, and the gel is mobile, but with a plug flow region of constant velocity near the gas-gel interface. Finally, at high enough gas velocity, a fully developed velocity field in the gel is created.

The parameters for the gel displacement model were evaluated by experiments. We examined the filter cake formation by pumping the fracture fluid through a conductivity cell, allowing leakoff to build the filter cake, measuring the cake thickness, and flowing gas through the cell to simulate the cleanup process. The results show that the yield stress of the residual gel plays a critical role in gel cleanup.