bluuebunny/crossref_metadata_2025 huggingface dataset:
Validation of T2-Bin Derived Permeability - A Case Study in Carbonates
Authors: Kneedy Jason , Smith Charles H , Ramakrishna Sandeep
Published: October 2011

The Atoka Wash in Oklahoma is a segment of the arkosic detrital material that eroded from the Wichita Mountain uplift. The rock ranges in age from Precambrian to Middle Pennsylvanian. The distinguishing characteristic is the composition of carbonate matrix material. The deposition can vary from finely grained to very course, depending upon the energy of transport.

Petrophysical properties of this rock contributed to confusion over the ability of the rock to produce hydrocarbon and the volume of reserves possible. Standard triple-combo logs were the logs typically run to evaluate the formation. Completions would be attempted when density/neutron crossplot porosity was in excess of 8%. Still, many completion attempts were unsuccessful, as the reservoirs would not produce at commercial rates. As one unsuccessful attempt followed another, drilling for this horizon became a discouraging and costly business.

The advent of T2 bin-derived permeability from NMR measurements cast this formation in a new light. NMR logs were used to evaluate other horizons in wells, and data was acquired in certain wells where mud logs indicated shows in this Atoka Wash. The surprising result was the existence of high-permeability areas in parts of the well with very low porosity. Some wells had indicated density/neutron porosity of less than 3% but with excellent indications of permeability from the T2 bin distribution. Completion attempts were made in some of these NMR-indicated productive zones with excellent results.

This paper presents the observed logs and the techniques used to ascertain these productive horizons. The usefulness of NMR bin-derived permeability to design completions is also emphasized. Finally, we will provide a comparison of the calculated productivity versus actual production for a series of these Atoka Wash wells, thereby validating the derivation and application of this NMR T2 bin-derived permeability.
Novel Transient Electromagnetic Borehole System for Reservoir Monitoring
Authors: Dutta Sushant M. , Reiderman Arcady , Schoonover Larry G. , Rabinovich Michael B.
Published: October 2011

In this paper we describe a novel transient electromagnetic borehole system for reservoir monitoring that has important advantages over existing borehole electromagnetic technology. This work is based on computer simulations of waterflooded reservoir models that demonstrate the effectiveness of this technology for reservoir monitoring.

Conventional and enhanced oil recovery processes such as waterflooding, steam flooding, and chemical flooding cause key changes in reservoir fluid composition over time. The proposed transient electromagnetic borehole technology can be used for fluid-front monitoring and to detect bypassed pay in reservoirs.

Existing cross-well borehole electromagnetic technology has shown potential for detecting changes in the reservoir over time by measuring resistivity contrasts. However, this approach has limitations, most notably that the measurements are limited to the region between a pair of wells. We show that transient measurements have a distinct advantage over traditional continuous-wave measurements in that different segments of the transient signal can be mapped to different regions of the formation. Furthermore, the measured transient signal experiences no interference from the transmitter because the transmitter is silent when the formation signal is acquired. This technology eliminates the need for using at least two separate wells simultaneously, and it results in better spatial resolution for the region close to the well. We use a realistic model of a waterflooded reservoir as a benchmark to present several three-dimensional (3-D) transient simulation results, demonstrating that this technology can provide deep (up to 300 m) and azimuthally selective measurements.

As opposed to cross-well technology, the proposed technique does not need a multifrequency, multispacing transmitter-receiver system or wireline logging equipment. It can be implemented as a permanent sensor system in the borehole. It can potentially also be used to monitor CO2 movement in carbon capture and sequestration (CCS) applications. The 3-D transient electromagnetic computer simulations performed for this work are a significant addition to the knowledgebase of the industry.
Expansion of Field Testing and Application of New Hybrid Drill Bit
Authors: Dolezal Tisha , Felderhoff Floyd , Holliday Alan , Bruton Greg
Published: October 2011

Improvements in drilling performance in key applications around the world continue to focus on reducing vibrations of the system consisting of the drill bit, bottomhole assembly (BHA) and drillstring. These vibrations can take the form of whirl, stick-slip, bit bounce or combinations of these, leading to drilling inefficiencies. Many efforts are under way to control and manage these vibrations and develop tools that can withstand the higher vibrations seen in today's drilling environment.

Introduction of the most-recent design of a hybrid drill bit took place in 2009 with the presentation of IADC/SPE paper 128741. It was shown to be a viable drilling tool for potentially difficult or problem-prone applications. This paper covers the ongoing development work on the hybrid bit technology which combines elements of polycrystalline diamond compact (PDC) and tungsten carbide insert (TCI) bits. Testing is now taking place on a large scale and the results confirm the potential benefits revealed in the early prototype testing.

Early tests of the hybrid bits were designed to show that it is sufficiently robust to drill and hold up under normal drilling. The next 100+ runs were targeted at areas where both traditional PDC and TCI drill bits struggle and the hybrid bit proved to be both faster and more durable than the conventional bits. This was achieved through the synergy of the smooth running action of the rolling cutters with the sharp cutting elements on the fixed PDC bit blades.

This paper details the knowledge gained in drilling over 167,000 feet just over 10,100 hours that has led to further design improvements and a better definition of the applications in which a hybrid bit can deliver superior performance. These applications are generally in the harder and hard-interbedded formations. The targeting of the hybrid technology is enabling problem wells to be finished sooner and at lower cost while still avoiding dynamic dysfunctions commonly seen. Results of all hybrid runs in a wide range of applications will be compared and recommendations will be made on where this technology can provide the most significant improvements.
Field Application of a New Proppant Detection Technology
Authors: Duenckel Robert J. , Smith Harry D. , Warren William A. , Grae Abram D.
Published: October 2011

Traditional proppant placement evaluation in hydraulically induced fractures has utilized detection of radioactive tracers pumped down hole with the proppant. We are proposing new methods for proppant placement determination. The proppant placement determination method described in this paper eliminates down hole placement of radioactive materials. A thermal neutron absorbing compound is inseparably incorporated into a ceramic proppant during manufacturing in sufficiently low concentration that it does not affect proppant properties. Proppant is detected using standard compensated neutron tools or pulsed neutron tools, with detection based on the high thermal neutron absorptive properties of the compound relative to downhole constituents.

Specifically, proppant is detected using after-frac compensated neutron logs combined with corresponding before-frac logs. Increased thermal neutron absorption by the compound reduces count rates in the near and far detectors, with approximately the same percentage reduction observed in each detector, leaving the N/F ratio unchanged. One detection method utilizes a comparison of before-frac log count rates and after-frac count rates, with reduced after-frac count rates observed in zones containing proppant. A second detection method, especially useful when formation gas saturations change, involves only the after-frac log. Since the near to far detector count ratio is unaffected by proppant, after-frac count rates predicted from the ratio will also be unaffected. These computed/synthetic count rates will be greater than the observed after-frac count rates in intervals containing proppant.

This paper will describe the results of applications of the new detectable proppant in wells in South Texas and Wyoming. The location of the detectable proppant was determined from analysis of before-frac and after-frac compensated neutron logs.
Advanced Logging-While-Drilling Formation Evaluation Case Study, North Slope, Alaska
Authors: Hastings Doug , Armfield Bart , Hupp Douglas
Published: October 2011

Efficient operations are critical to the successful development of North Slope, Alaska, prospects where an abbreviated drilling season and rig-time costs constrain project planning. Logging While Drilling (LWD) provides the real-time data used to make essential well construction decisions. In addition, data are acquired in troublesome formations with complex well profiles where acquisition of wireline data would be overly risky or sometimes impossible. This paper highlights a particular case in which one operator used LWD technology and strategic evaluation to manage risk and significantly reduce operating costs while drilling a well in the Sag River formation.

The Sag River formation is fine-grained sandstone with variable permeability controlled by porosity and lithology. The permeability profile causes a significant transition zone at the oil/water contact. Reservoir engineering studies require an accurate understanding of the formation permeability to determine the optimal well placement strategy, and horizontal wellbores are necessary to maximize exposure in the most productive zones. Considering these factors, it is critical to understand permeability, pore size distribution, traditional porosity, and saturation properties for successful development.

Because of considerable wellbore stability risk in the Kingak shale, LWD services were used to acquire reservoir data. The LWD services used to evaluate this reservoir measured bulk density, neutron porosity, gamma ray, resistivity, spectroscopy, capture sigma, magnetic resonance porosity and T2 spectrum, permeability, pore size distribution, annular pressure, formation pressure, and a computed mobility. Acquiring the necessary formation data with LWD tools saved 3 days of rig time and eliminated stuck tool and fishing risks associated with wireline evaluation. Furthermore, a casing string that would have been used to facilitate prolonged reservoir evaluation operations after drilling was eliminated.

Data interpretation showed that the Sag River formation at this location was oil bearing and that the higher-than-expected water saturation was actually bound water. The spectroscopy results helped refine the clay volume as well as the volume of non-quartz minerals. The results of this evaluation will be used in subsequent reservoir modeling to identify the best approach to exploiting this reservoir. A comparison of the core evaluation with the petrophysical interpretation is also presented.
Geology-guided Quantification of Production-Forecast Uncertainty in Dynamic Model Inversion
Authors: Maucec Marko , Cullick Stan , Shi Genbao
Published: October 2011

The presence of a large number of geologic uncertainties and limited well data typically increase the challenges associated with hydrocarbon recovery forecasting. Although recent advances in geologic modeling enable the automation of the model generation process by means of next-generation geostatistical tools, the computation of the reservoir dynamic response with full-physics reservoir simulation remains a computationally expensive task, which in practice requires considering only a few (but which?) of the many probable realizations.

This paper presents a workflow that demonstrates the potential of capturing the inherent model uncertainty more accurately and assists in production-forecast business decisions. This workflow uses a history matching approach that directly interfaces the Earth modeling software with a forward simulator. It relies on the rapid characterization of the main features of the geologic uncertainty space, represented by an ensemble of sufficiently diverse history matched model realizations at the high-resolution geological scale. This workflow generates a more accurate result by obeying known geostatistics (variograms) and well constraints.

We implement a multi-step, Bayesian Markov chain Monte Carlo inversion in which the proxy model is guided by streamline-based sensitivities. This process eliminates the need to run a forward simulation for each model realization, which significantly reduces the computation time. Efficient model parameterization and updates in the wave-number domain, based on discrete cosine transform (DCT), is used for fast characterization of the main features of the geologic uncertainty space, including structural framework, stratigraphic layering, facies distribution, and petrophysical properties. The application of the history matching workflow is demonstrated with a case study the combines the geological model with approximately 900K cells, four different depositional environments, and 30 wells with a 10-year waterflood history.

Finally, the method is described to dynamically rank the reconciled model realizations to identify the highest potential of capturing bypassed oil and to optimize business decisions for implementing improved oil recovery (IOR). The main features include the following:

Calculation of pattern-dissimilarity distances, which distinguish two individual model realization in terms of recovery response Deployment of very fast streamlined simulations to evaluate distances Application of pattern-recognition techniques to assign several realizations, representative for production forecasting, to full-physics simulation Derivation of the probability distribution of dynamic model responses (e.g., recovery factors) from the intelligently selected simulation runs
Nanoparticle and Microparticle Flow in Porous and Fractured Media: An Experimental Study
Authors: Alaskar Mohammed , Ames Morgan , Connor Steve , Liu Chong , Cui Yi , Li Kewen , Horne Roland
Published: October 2011

The goal of this research was to develop methods of acquiring data about reservoir pressure and temperature, near the wellbore and far out in the formation, and correlating such information to fracture connectivity and geometry. Existing reservoir characterization tools allow for pressure and temperature to be measured only at the wellbore. The development of temperature- and pressure-sensitive nanosensors will enable in-situ measurements within the reservoir. This paper provides the details of the experimental work performed in the process of developing temperature and pressure nanosensors. The study investigated parameters involved in the mobility of nanoparticles through porous and fractured media. These parameters include particle size or size distribution, shape and surface charge or affinity to rock materials.

The principal findings of this study were that spherically shaped nanoparticles with surface charge compatible with that expected in porous media are most likely to be transported successfully through formation rock, without being trapped due to physical straining, chemical or electrostatic effects. Silica nanoparticles were passed through Berea sandstone and long slim-tube sand-packs without difficulty. We found that tin-bismuth nanoparticles of 200 nm and smaller were transported through Berea sandstone. Larger particles were trapped at the inlet of the core, indicating that there was an optimum particle size range. We also found that the entrapment of silver nanowires was primarily due to their shape. This conclusion was supported by the recovery of the spherical silver nanoparticles with the same surface characteristics. The entrapment of hematite nanorice was attributed to its affinity to the porous media caused by surface charge. The hematite coated with surfactant (which modified its surface charge to one compatible with flow media) flowed through the glass beads, emphasizing the importance of particles surface charge.

Preliminary investigation of the flow mechanism of nanoparticles through a naturally fractured greywacke core was conducted by injecting fluorescent silica microspheres. We found that silica microspheres of different sizes (smaller than fracture opening) could be transported through the fracture. We demonstrated the possibility of using microspheres to estimate fracture aperture by injecting a polydisperse microsphere sample. It was observed that only spheres of 20 μm and smaller were transported. This result agreed reasonably well with the measurement of hydraulic fracture aperture (27 μm) as determined by the cubic law.
Quick Estimate of Initial Production from Stimulated Reservoirs with Complex Hydraulic Fracture Network
Authors: Xu Wenyue , Li James , Mike Du C.
Published: October 2011

Models of complex fracture networks created by hydraulic fracturing stimulation have been developed to analyze fracture network growth and proppant placement, mostly for wells drilled into shale gas or tight sand gas reservoirs. However, there is still a lack of quick solutions for estimating the rate of production from these wells analytically. This paper presents a few simplified analytic well production models developed recently based on the laws of mass and momentum conservation, including:

The relative magnitude of pressure drops along fractures and across shale formation The effect of a damaged fracture surface layer on production Solutions for gas flow from reservoir formation into a fracture or parallel fractures with transient fracture fluid pressure Scaling of the rate of this flow with time and fracture spacing Coupling of fluid flows from reservoir formation into and along fractures of a complex hydraulic fracture network

The models were validated against numerical simulations using a commercial simulator for gas production from a single planar fracture, a cluster of parallel fractures and a wiremesh fracture network. These analytical models provide fast and convenient tools for fracturing job design and post-job analysis of hydraulic fracturing stimulation. They may also find potential applications to broader areas.
Evaluation and Improvement of Gravel Pack Treatments Using Advanced Downhole Pressure Analysis
Authors: Wassouf Philip , Jain Samyak , Dannish Greg , Ramnarine Alan
Published: October 2011

Openhole gravel packing (OHGP) is emerging as one of the primary completion techniques in horizontal wells with sanding tendencies. As the experience level for this technique increases, OHGP applications are extending to more challenging environments, including longer intervals. Because many of these jobs are performed in offshore and deep water environments where the cost of failure is substantial, a thorough knowledge of all aspects of treatment design, execution, and evaluation is required. While many OHGPs have been performed, the current understanding of both treatment success and failure is limited due to either a lack of sufficient data (such as bottomhole pressure and temperature) or experience in its evaluation.

This paper introduces data analysis techniques that can be used for a more detailed insight into a variety of downhole events, including packing mechanisms, fluid changes, and system frictions. The pressure analysis technique presented isolates sections of the flow path and identifies these events within the system for accurate treatment analysis. The combination of this technique and volumetric and material balance calculations ensures a detailed quantitative approach to gravel pack data analysis.

The background theory and its application are discussed through a detailed case study of a well in the Poinsettia field, offshore Trinidad, in which downhole gauge data was used to identify and quantitatively analyze the final pack integrity. The analysis technique was able to confirm complete coverage of the screens as well as the packing mechanism by which the gravel was placed. This approach to gravel pack evaluation maximizes the value of downhole memory gauge data, yielding an improvement in the knowledge of downhole processes and facilitating the continuous improvement of OHGP job design and execution.
Economics and Technology Drive Development of Unconventional Oil and Gas Reservoirs: Lessons Learned in the United States
Authors: Flores C. P. , Holditch S. A. , Ayers W. B.
Published: October 2011

Development of unconventional hydrocarbons is increasingly important as conventional resources decline and oil and gas demand increases. The concept of the energy resource triangle (Masters 1979) suggests unconventional oil and gas are abundant, but the exploitation of these resources is particularly sensitive to both technology and commodity prices. In this paper, we assess the effects of technology and various geopolitical and economic events on historic U.S. unconventional oil and gas production, in the context of Master's resource triangle theory (RTT).

We used the Austin Chalk as the base case and then extended the study to seven other unconventional plays. The two approaches used to evaluate the RTT were: (1) correlation of commodity prices and technology with drilling activity, and (2) production forecasting using decline curve analysis. Spearman's Rank Correlation Coefficient was used technique to establish the dependence between active wells, rig count, and commodity price variables. Decline curve analyses allowed us to estimate the increase in production from different scenarios of high price or technology.

Results support the RTT concept: higher commodity prices encouraged the introduction of new technologies, and increased drilling activity and boosted production from unconventional plays. For example, horizontal drilling revived older plays, such as the Austin Chalk. Moreover, the combination of horizontals wells and advanced fracture stimulation techniques led to the expansion of shale plays such as the Barnett and the Bakken. Correlation of commodity prices with drilling activity demonstrated that, during periods of high commodity prices, the number of producing wells increased an average of 75%. Using decline curve analysis, a maximum of $50 billion oil and gas production was forecasted via vertical, fractured wells (conventional technologies) and an economic cutoff of 5 BOE/d/well. However, current production plans, using improved technologies, suggest that the assessed plays may produce an additional $320 billion oil plus gas.

U.S. production from unconventional reservoirs, stimulated by a federal tax credit, technology advances, and high commodity prices, encourage operators to dip lower into the resource triangle. Lessons learned in the U.S. may encourage the exploitation of unconventional oil and gas worldwide.
Best Practices for Effective Use of Technology in the Classroom
Authors: Fiffick William S. , Smith Michael R.
Published: October 2011

Classroom training takes on a more crucial role as engineers, scientists, technologists, and operations personnel are challenged to solve new and more complex problems; the ability to properly apply oil field technology becomes even more crucial to our success. While much of the training provided to those entering the workforce is built on foundational concepts, products, and processes, much more is required. New applications of computer technology, processes, practices, and products are constantly being invented, refined, and/or improved. The ability to quickly and systematically apply new technology can save hundreds of work hours. Applying new technology can also pay great dividends by helping new field engineers learn technology and foster continuous improvement. Conventional teaching methods are still viable today in specific situations. The use of computers and proprietary software requires different processes and new methods of instructional delivery. To facilitate the process, computer software management tools can greatly enhance the teaching process. So, how do we capture that knowledge and those lessons learned? What best practices can be modeled? How do we leverage learning technology to archive and transfer these important lessons? How do we optimize the time commitments from our instructors? What emerging technologies are available which may assist with the capture, transfer, and delivery efforts? How are the varied learning methodologies satisfied?

The following is a case study from a major oil field services company outlining effective and efficient technology transfer efforts in the classroom. Best practices as well as lessons learned are discussed.
Deep Fracture Imaging Around the Wellbore Using Dipole Acoustic Logging
Authors: Bolshakov Alexei , Patterson Doug , Lan Chun
Published: October 2011

Characterizing fractures in reservoir rocks is important because they provide critical conduits for hydrocarbon production from the reservoir into the wellbore. The standard method uses shallow borehole imaging services, both acoustic and resistivity, which essentially look at the intersection of the fractures at the borehole wall. Cross-dipole technology has extended the depth of evaluation some 2 to 4 ft around the borehole by measuring the fracture-induced azimuthal shear-wave anisotropy. A recently developed shear-wave reflection imaging technique provides a method for fracture characterization in a much larger volume around the borehole with a radial extent of approximately 60 ft. This technique uses a dipole acoustic tool to generate shear waves that radiate away from the borehole and strike a fracture surface. The tool also records the shear reflection from the fracture. The shear-wave reflection, particularly the SH waves polarizing parallel to the fracture surface, is especially sensitive to open fractures, enabling the fractures to be imaged using this dipole-shear reflection data. We use case examples to demonstrate the effectiveness of this shear-wave imaging technology that maps fractures up to 60 ft away and even detects fractures that do not intercept the borehole.
New Acoustic Log Data Interpretation for Gas-bearing Shaly Sands
Authors: Lan Chun , Patterson Douglas J. , Tang Xiaoming
Published: October 2011

Acoustic wave propagation in a sandstone formation depends on porosity, mineralogy, rock matrix elastic moduli, and fluid saturation. The wave velocities are directly linked to pore space compressibility, which forms the basis of many acoustic interpretation methods for identifying gas-bearing sands, e.g., Castagna's cross-plot method and Murphy et al.'s modulus decomposition method, etc. The latter method detects the presence of gas by comparing acoustic log data with synthetic data computed for full saturated water, oil and water conditions. A basic assumption of this method is that the ratio of the bulk and shear moduli under gas-saturation is invariant for sandstones. This assumption limits the application of this method only to the clean sand scenario. For shaly sands with significant clay content, this moduli ratio is not a constant value, and the interpretation based on the constant ratio assumption may become invalid.

We developed a new acoustic interpretation method for gas indication in the shaly sandstone formation. This method determines the variation of the dry frame bulk-to-shear moduli ratio by calibrating it in a water-bearing zone. This calibration establishes the correlation between the moduli ratio and shale content. The established correlation is then applied throughout the zone of interest to calculate pore fluid bulk modulus and gas saturation. The calculation result enables a direct interpretation of gas-bearing sands. To apply this method, acoustic compressional and shear velocity, gamma ray, and density log data are required. In case there is no water-bearing zone for the calibration, default ratio values can be used.

This method has been successfully tested in several wells. Two examples are used to demonstrate the method and its application. In both examples, the new results are compared with those from Murphy et al.'s method to demonstrate the marked improvement of the new method for shaly sands. Neutron and density results and resistivity log data further validate the new results.
Joint Inversion of 4D Seismic and Production Data
Authors: Landa Jorge L. , Kumar Dhananjay
Published: October 2011

We present a workflow for the quantitative integration of 4D seismic and production data into reservoir simulation models. Reservoir models are probabilistically history matched to 4D seismic and production historical data simultaneously. The timely incorporation of 4D seismic into reservoir models, coupled with the associated reduction of production forecast uncertainty, has a significant impact in the modern reservoir management of oil and gas fields. One of the outstanding features of the work presented is the use of the 4D seismic data at the seismic trace level (i.e. seismic wiggle) compared to the impedance level.

In the joint inversion approach, the reservoir models are jointly calibrated to the production data and the 4D seismic data simultaneously through a single inversion process. There is no need for separate seismic inversion for impedance or for pressure/saturation. The calibrated reservoir models honor both the historical production data and the 4D seismic traces.

The joint inversion ensures consistency among the observed 4D seismic traces, the observed production data, and the geological, seismic, petrophysical and flow models. This consistency, while it is guaranteed in the joint inversion, is difficult to attain through the traditional approach of separate inversion processes for 4D seismic and production data.

The joint inversion process seeks: a) to shorten the time between 4D seismic acquisition and its incorporation into reservoir models, b) to use 4D seismic in a quantitative way, and c) to reduce uncertainty in reservoir models and thus reduce uncertainty in the production forecasts.

This paper presents and discusses results from application of the joint inversion workflow to a synthetic field case based on a real field. The example covers the areas of a) history matching of flow simulation models to 4D seismic and production history, and b) estimation of uncertainty.

The joint inversion process requires a multidisciplinary effort. It involves the joint modeling of geology, flow simulation, rock physics, and seismic modeling under a common earth model, and thus it naturally fosters the efficient interaction among geologists, geophysicists, and reservoir engineers.
Improvement of Flow Properties of Heavy Oils Using Asphaltene Modifiers
Authors: Ovalles Cesar , Rogel Estrella , Segerstrom John
Published: October 2011

The presence of asphaltenes and its tendency to form aggregates play a fundamental role on the high viscosity observed for heavy and extra heavy crude oils (H/XH). It has been shown that by removing the asphaltenes, a reduction of two to three orders of magnitude on the viscosity of the deasphalted product is obtained. It has also been demonstrated that asphaltenes interact extensively within themselves and with other similar molecules forming extended networks. By this way, the asphaltene solutions have relatively high viscosities and, these values increase exponentially with the concentration. In this work, the viscosity of H/XH is reduced by the use of additives that can act as modifiers of the aggregation behavior of asphaltenes. Several commercially available additives were evaluated at high (0.1-3%) and low (50 up to 400 ppm) concentrations at laboratory (20 mL) and bench (8 L) scales. For an extra heavy crude oil/diluent blends (75/25 wt.), the presence of the additives led to viscosity reductions up to 18 to 25% with respect to the blend without additives. Particle size measurements indicated that the presence of the Asphaltene Modifiers shifted the asphaltene distributions from "flocculated" (>1 µm) to "stabilized" asphaltenes (~0.1 µm) and give evidence of the effect of these additives on the aggregation behavior of asphaltenes. The commercial applications of these additives are also discussed.
The Effect of Mechanical Properties Anisotropy in the Generation of Hydraulic Fractures in Organic Shales
Authors: Waters George A. , Lewis Richard E. , Bentley Doug C.
Published: October 2011

Organic shale reservoirs have very low matrix permeabilities. An extensive conductive hydraulic fracture network is necessary to impose a pressure drop in the formation to produce hydrocarbons at an economic rate. In addition, horizontal wells permit the initiation of multiple hydraulic fractures within the reservoir section of the organic shale. The location of the lateral landing point can have a significant impact on hydraulic fracture geometry.

The stimulated fracture system is influenced by the extensive horizontal laminations that are pervasive in shale reservoirs. The laminations will strongly influence the hydraulic fracture height because of the difference in rock mechanical properties measured normal and parallel to the bedding planes. In order to accurately predict fracturing height from logs in this environment, these mechanical property differences must be taken into account.

A series of sonic logs have been run in organic shales and the stress profile generated from these logs has been estimated, accounting for the difference in mechanical properties in the vertical and horizontal directions. This stress profile has been calibrated to measured closure stresses acquired in-situ via micro-fracturing of multiple intervals in vertical, openhole environments. The results show that ignoring the impact of mechanical property anisotropy can lead to significant errors in the estimation of hydraulic fracture height. Correspondingly, the optimal landing point of a horizontal wellbore may not be selected when ignoring this effect. This can result in excessively high fracture initiation pressures, difficulty achieving injection rate or proppant placement, and unexpected fracture height growth. Simulations of hydraulic fracture width indicate that thin high-stress intervals can create pinch points that limit vertical fracture conductivity. Each of these factors can result in un-optimized hydrocarbon productivity.
Impact of Fracture Growth on Well Injectivity and Reservoir Sweep during Waterflood and Chemical EOR Processes
Authors: Lee Kyunghaeng , Huh Chun , Sharma Mukul M.
Published: October 2011

During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; (iii) thermal stresses induced by cold water injection; and (iv) stress and fracture reorientation due to poroelastic effect and rock displacements near fractures. Dynamic fracture growth due to particle plugging, thermal stresses, and complex polymer rheology during chemical flooding, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance.

It is shown that both injected particles and polymers play an important role in fracture propagation. Oil recovery and reservoir sweep during the injection of water or polymer into a homogeneous reservoir is relatively unaffected by the propagation of an injection induced fracture. However, in multi-layered reservoirs, reservoir sweep and oil recovery are impacted significantly by a combination of particulate plugging, polymer rheology, thermal stresses, and fracture growth. The results of a dynamically growing fracture obtained from our fracture growth model differ substantially from the oil recovery obtained for a static fracture. The shear rate dependence of the polymer rheology is critical in determining the injectivity, fracture growth, and oil recovery.
Comparison of Multiphase Pumping Technologies for Subsea and Downhole Applications
Authors: Hua Gong , Falcone Gioia , Teodoriu Catalin , Morrison Gerald L.
Published: October 2011

The selection criteria for multiphase boosting options remain somewhat subjective and frequently influenced by the vendors’ data, which may mask potential limitations of this emerging technology. Existing literature on multiphase pumping tends to focus on a certain pump type for a specific field application, but does not provide more generalized criteria for the selection of multiphase boosting solutions from among those available in the market. A comprehensive literature review into the working principles of the major pump types identified the intrinsic advantages and limitations of each technology for subsea and downhole applications.

The survey showed that, for subsea application, both the twin-screw pump (TSP) and the helico-axial pump (HAP) can handle high suction gas volume fraction (GVF) with a fluid recycling system, or flow mixer. Thus, GVF is not a discriminating factor. The positive displacement principle allows TSPs to work with very low suction pressure, but limits their operating range because of the dependency of flowrate on their relatively low speed. However, these pumps can handle highly viscous fluid. The roto-dynamic concept enables the differential pressure of HAPs to self-adjust to any instantaneous change in suction GVF, and to achieve higher flowrate if sufficient suction pressure is maintained. As HAPs usually run at higher speed, they offer a wider operating range.

For subsea application, HAPs appear to be a better option than TSPs, because they offer higher operation flexibility and have a better installation track record.

For downhole applications, the electric submersible pump (ESP) and the progressing cavity pump (PCP) are the outstanding favorites, with the latter being preferred for lifting streams that are viscous or with high sand content. For GVF up to 70%, the roto-dynamic pump (RDP) is becoming a popular solution. Although it is claimed that the downhole twin-screw pump (DTSP) can handle up to 98% GVF, it is not yet widely accepted in the field.
Correlation of Surfactant-Induced Flow Behavior Modification in Gas Condensate Reservoirs with Dynamic Contact Angles and Spreading
Authors: Zheng Y. , Saikia B. , Rao D. N.
Published: October 2011

The commonly encountered condensate blockage problem causes severe impairment of gas productivity as the flowing bottom-hole pressure falls below the dew point in gas condensate reservoirs. This study investigates the potential for improving gas relative permeability and enhancing oil (condensate) recovery by using low-cost surfactants to alter wettability in the near wellbore region as well as fluid-fluid spreading coefficient. Surfactant-induced wettability alterations have been derived from experimental measurements of dynamic contact angles and oil-water relative permeabilities.

Coreflood experiments were conducted using two different rock-fluids systems: (1) Berea sandstone, condensate, synthetic brine and nitrogen; and (2) Parker sandstone, artificial retrograde gas, and synthetic brine at elevated pressures. The anionic surfactant, which was more effective in our previous work, has been used in this coreflood study. Contact angles were measured on quartz surface using Dual-Drop-Dual-Crystal (DDDC) technique and spreading coefficient was determined through measuring interfacial tensions using pendent drop method by drop shape analysis technique. Oil-water relative permeabilities were generated by history matching condensate recovery and pressure drop data obtained from the coreflood experiments.

The shifts in oil-water relative permeability ratio curves indicated that the wettability of this Berea core-condensate-brine system altered to intermediate-wet induced by this anionic surfactant. The contact angle measurements for this system with surfactant also substantiated the wettability alterations to intermediate-wet. The results of subsequent gasflood using nitrogen showed 82% improvement in gas relative permeability for this system. Positive spreading coefficient obtained in all Berea core cases indicates that it has less influence on enhanced gas relative permeability compared to wettability alteration. Corefloods using artificially prepared retrograde gas mixture creating in-situ retrograde gas condensation within the core system also showed the improvement in gas relative permeability. This study thus demonstrates that surfactant-induced alteration of wettability and spreading coefficient have the benefits for improving gas and condensate production by mitigating the condensate blockage problem.
Field Development Optimization Under Uncertainty: Screening-Models for Decision Making
Authors: Ogunyomi B. A. , Jablonowski C. J. , Lake Larry W.
Published: October 2011

In this study we develop an integrated asset model (IAM) for a greenfield offshore oil development and demonstrate its use in an uncertainty analysis workflow. The proposed framework enables a systematic quantification of the uncertainties and provides users with an in-depth understanding of the impact of uncertainties on major design and operational decisions. The IAM is specified for a hypothetical deepwater field to investigate three decisions: optimal initial facility capacity, optimal number of pre-drilled wells, and the optimal number of drilling rigs. The uncertainty analysis addresses two critical variables: reservoir thickness and the transmissibility between the reservoir compartments.

This work develops and demonstrates a fast-solving physics-based integrated optimization model where production, drilling, and facility expansion decisions are endogenous (that is, the model solves for these variables implicitly) and thus provides higher quality (and faster) guidance in many cases than the design-of-experiments and response surface workflows currently being used in the oil and gas industry.
Experimental and Modeling Study of Vapor-Liquid Equilibrium for Propane-Heavy Crude Systems at High Temperature Conditions
Authors: Kariznovi Mohammad , Nourozieh Hossein , Abedi Jalal
Published: October 2011

Heavy oil and extra heavy oil reserves have attracted increasing attention in recent years as alternatives to conventional oil reservoirs. Different technologies, such as vapor extraction and steam-assisted gravity drainage, have been developed for in situ extraction of these resources. It was recently found that the compounded effects of solvents and heat on the viscosity of heavy oil can provide oil production rates that may be equivalent to or higher than those from the injection of steam alone. In addition, this improved recovery product is complemented by a process that uses less fresh water and has lower greenhouse gas emissions.

There is, however, a distinct lack of basic data and mechanistic knowledge relevant to the solvent/heat-assisted recovery processes. Even the most fundamental experimental data, such as the solubility of commonly used solvents in oil, are not available. The quantitative effects of solvent on oil viscosity and phase behaviors at temperatures approaching the conditions of the in situ steam processes are also not well understood.

In the present study, the solubility of propane in an extra heavy oil and the saturated phase densities and viscosities were measured for temperatures from 100°C to 200°C at different pressures. These temperatures and pressures approach the conditions of the in situ steam processes in which both solvent and steam contribute to a higher reduction of oil viscosity.

The experimental results showed that, at high temperatures, the saturated phase viscosities converged as the pressure increased. In addition, the density data demonstrated crossover at an intermediate pressure for different temperatures. The data on the solubility and the physical properties can be utilized for the optimization of solvent/heat-assisted recovery processes. The observed phase behavior was modeled using an equation of state model, closely matching the experimental results. Such a model will be useful in the development of solvent/heat-assisted-recovery processes.
Perforating High-Pressure Deepwater Wells in the Gulf of Mexico
Authors: Baumann Carlos , Williams Harvey , Korf Timothy , Pourciau Robert
Published: October 2011

A large number of well perforation jobs are conducted successfully worldwide each year. However, gunshock related damage poses a significant risk when perforating high-pressure wells. This paper presents gunshock studies done with a simulation tool specifically developed to predict perforating gunshock loads and the associated structural loads on the equipment. This simulation effort includes results from seventeen Tubing Conveyed Perforating (TCP) jobs on high-pressure deepwater wells, with pressures ranging from 13,800 psi to the highest pressure wells ever perforated in the Gulf of Mexico at 20,700 psi. The results show very good agreement between software predictions and actual field data.

When planning perforating operations in high-pressure wells, engineers strive to minimize the risk of equipment damage from perforating gunshock loads, such as bent tubing and damage to packers. The risk of equipment damage from perforating gunshock loads increases very rapidly as the bottomhole pressure increases beyond 15,000 psi. The simulation tool used to perform gunshock studies is fast and can reliably identify perforating jobs that have a high possibility of gunshock related damage. For those cases where the chance of gunshock damage is high, design changes can be implemented to reduce or eliminate those potential risks.

In this review, computational predictions are compared with high-speed pressure gauge data, with the residual deformation of shock absorbers, and with high speed acceleration data. Fast gauge pressure data shows that predicted wellbore pressure transients are sufficiently accurate in magnitude and time. Peak pressure amplitudes measured at the gauges are, on average, within 8 percent of the predicted values. Residual deformations of shock absorbers correlate favorably with predicted peak axial loads, and available fast gauge acceleration data shows that the asymptotic gunstring acceleration is well predicted, both in amplitude and frequency. The ability to identify and reduce risks in perforating operations is important because the value of deepwater wells is very high and rig time losses are costly. With the software tool presented in this paper, engineers can optimize high-pressure well perforation designs in order to minimize the likelihood of gunshock related damage and the associated rig time losses.