bluuebunny/crossref_metadata_2025 huggingface dataset:
Advances in World Oil Shale Production Technologies
Authors: Crawford Peter M. , Biglarbigi Khosrow , Dammer Anton R. , Knaus Emily
Published: September 2008

The development of domestic oil shale resources has regained significant attention in the past few years. Several factors have contributed to this, including high oil prices, emerging recovery technologies, increasing world demand for liquid hydrocarbons, and the continued decline in U.S. conventional oil production. In recent years, several initiatives have been taken by government and the private sector to encourage the development of a domestic oil shale industry.

The United States has the largest and most concentrated deposits of oil shale in the world, including nearly 2.0 trillion barrels across the eastern and western states. However, until recently, U.S. oil shale development efforts have largely been in hiatus. Several other nations also have significant oil shale resources, including China, Estonia, Israel, and Turkey. Since 2006, more than 25 U.S. companies have made public information about new oil shale technologies. Other non-U.S. companies have also achieved significant advances.

An analysis has been conducted to identify and profile advanced oil shale technologies that improve performance and help mitigate barriers to commercialization. Advances include reduced water use, improved energy efficiency and net energy balance, better carbon and emissions management, reduced surface impact, spent shale use and disposal, and effective groundwater protection. The analysis addresses both surface and in-situ processes and includes technologies intended to produce liquid fuels or to fire electric power generation.

Notable examples include the Kiviter and Galoter retorts in use in Estonia, the Alberta Taciuk Processor considered for use by OSEC in Utah, Shell's In-Situ Conversion process under consideration in Colorado and in Jordan, Petrobras’ Petrosix Gas Combustion Retort (and variations) in use in Brazil, the Raytheon/CF radio-frequency with critical fluids technology just licensed by Schlumberger, and the EcoShale process under development in Utah.

The results of the analysis suggest significant promise that production of oil from oil shale can be technically and economically feasible while meeting rigorous industry and public standards for technical performance, resource conservation, and environmental protection. It also identifies areas where further research, development, and demonstration are needed.
The Determination of Minimum Tested Volume from the Deconvolution of Well Test Pressure Transients
Authors: Whittle Tim , Gringarten Alain
Published: September 2008

Radius of investigation and tested volume are important results of well test analysis which can make or break future field development. Currently, their evaluation is either approximate or relies on a complete analysis of the transient pressure response using an appropriate model. A new method is proposed that uses the deconvolved derivative response to determine a minimum tested volume. It is accurate and does not rely on further transient analysis.

The method can be applied to any oil or gas well test. It is simple and only requires input of data that is known at the time of testing. Furthermore, if the uncertainty in the deconvolution is quantified, then the uncertainty in tested volume is also defined.

Field examples of both oil and gas well tests are presented which demonstrate how tested volume is easily calculated. Radius of investigation is calculated from the tested volume by making assumptions about the reservoir geometry. The method relies on a good deconvolution algorithm which can also compute the error bars in the derivative response.

Recent advances in deconvolution algorithms have enabled the use of this simple but powerful new method to accurately calculate tested volume without the need for complex transient analysis.
A Comprehensive Study on the Effect of Compliance on Productivity
Authors: Hembling Drew , Lauritzen Eric , Phillips James , Rabba Ali , Jones Colin , Beare Steve , Morgan Quentin , Cameron John
Published: September 2008

Expandable sand screens are a globally accepted sand control system with more than 600 installations worldwide across all vendors. A growing body of data suggests that when compliantly expanded in openhole they perform very well, with consistently low skins and high PIs. Where comparisons have been done, the expandable screens perform at least as well as other sand exclusion systems such as standalone screens and openhole gravel packs. There are a number of possible reasons for the high performance:

The ESS presents a large open area to the formation. This gives a low pressure drop across the screen and minimizes the possibility of plugging to a minimum. The compliant expansion into contact with the wellbore limits the zone of deformation around the hole. Compliance also improves filter cake clean up by reducing mixing with failed sand.

The effect of compliance has been investigated in two sets of experiments. The first was full scale test with a compliant expandable screen and a stand alone screen with an annulus. The expandable showed 60% higher productivity than the screen with an annulus. The second set of experiments was in a specially designed Perspex cell. This cell allowed the effect of an annulus to be investigated for a variety of different sands from well sorted to poorly sorted. The results show that the compliant screen has advantages in sand retention and 100% greater productivity.

Taken as a whole, the field results and the two types of experiment show in a very clear way the benefits on productivity of compliant sand screens.
Modeling Permeability in Tight Gas Sands Using Intelligent and Innovative Data Mining Techniques
Authors: Ali Liaqat , Bordoloi Sandip , Wardinsky Serene H.
Published: September 2008

Evaluation of gas potential in low permeability reservoirs (< 0.1 md) generally referred to as Tight Gas reservoirs is not very straight forward as in conventional reservoirs. This study is focused on modeling permeability in the Travis Peak Formation where there are many challenges. One may encounter low resistivity pay due to clay coated grains and alternating thin laminae of finer and coarser sandstones with distinctly different pore geometries, natural fractures, bituminous zones and multilateral fluvial channel sandstones in broad lenses. Core data is sparsely available. Most importantly, there are no structural features that may construe trapping mechanisms. In view of these challenges, a permeability model was developed primarily for the Travis Peak Formation of Robertson and Leon counties where it has produced 96 BCF of gas and 0.54 MMbbl of oil.

A permeability model was developed by integrating core and log data using the Adaptive Neuro Fuzzy Logic Inference System (ANFIS) that combines the functionality of neural network and fuzzy logic techniques. A combination of conventional logs such as lithology (GR, SP), porosity (RHOB, NPHI), deep and shallow resistivity logs were integrated with core data (porosity, permeability).

The results showed excellent agreement with measured core permeability values. The results of the conventional porosity-permeability transform are also presented for comparison purposes. Since the data has been used from the Travis Peak Formation of East Texas Basin comprising several counties, it is expected that the permeability model should be applicable anywhere in the basin.
Use of Combined Material Balance and Volumetric Analysis to Improve Performance Predictions In a Large Coproduction Field Project
Authors: Smith James E. , Payne Dalian V. , Desantis Cory L. , Broyles Owen L.
Published: September 2008

This paper describes the combined use of volumetric and material balance analysis to understand and predict performance of a large West Texas oil and gas field currently under coproduction.

The Keystone Ellenburger Field, located in Winkler County in the Permian Basin of West Texas, is a large field originally containing both an oil column and a gas cap, along with a moderate to strong water drive. The reservoir is a fractured carbonate with associated vugs and low matrix porosity but high effective permeability due to the natural fracturing. It has undergone a complex development history: primary oil production, gas reinjection and water injection, but since 1992 has been produced by coproduction of large volumes of water to increase gas and oil recovery. As the field matures and the operators confront lower pressures and productivities, along with higher operating and capital costs, we saw the need to develop a reliable predictive model of future performance. Prior efforts with conventional material balances and reservoir simulation have failed to meet expectations.

Because the field has high effective permeability, fluids in the reservoir appear to be in vertical equilibrium. Since 1992 we have acquired pressure and gas-liquid contact information through observation wells. This data, coupled with reservoir maps and production history, have allowed us to build and calibrate a spreadsheet which tracks fluids in place and estimates other parameters such as net water influx.

Reservoir maps were used to generate horizontal slices through the reservoir in order to estimate reservoir pore volume for a given slice through the reservoir. As reservoir pressure declines and the gas-liquid contact moves up or down, we can calculate water influx as well as refine such parameters as effective porosity, original oil and gas in place, and trapped gas saturation.

Based on the historical pressure decline and gas-liquid contact changes we have seen, and using the combined volumetric/material balance approach, we can predict much more accurately how the reservoir will behave under different future production schemes.

The method has shown us that significant gas remains to be recovered, but most of it exists as trapped gas in the water/oil leg of the reservoir. Continued coproduction will lower the reservoir pressure and the gas-liquid contact, both of which will allow additional gas to be produced.
Microseismic Deformation Rate Monitoring
Authors: Maxwell S. C. , Shemeta J. , Campbell E. , Quirk D.
Published: September 2008

Microseismic monitoring of hydraulic fractures is an important tool for imaging fracture networks and optimizing the reservoir engineering of the stimulation. The range of magnitudes of the recorded microseisms depends at the lower limit on the array sensitivity; while the upper limit varies significantly from site to site. In this paper the variation in the microseismic magnitude range is examined and compared with the injection and site characteristics. Although there are numerous potential factors effecting the seismic deformation, the energy of the pumping and state of stress appear to be the two dominant factors. However, interaction with pre-existing faults also results in increased deformation. Ultimately, this can potentially be used to design the stimulation to maximize the deformation. Characterization of the seismogenic potential is also important for seismic hazard assessment, as well as the design of passive monitoring.
Environmental Considerations Related to Oil Shale Development
Authors: Knaus Emily J. , Dammer Anton R.
Published: September 2008

Recently, public attention has been directed at global warming, greenhouse gases and overall environmental quality in the United States and around the world. Fuels production inherently produces carbon dioxide as a byproduct and the public and the legislature have deemed it necessary to consider these impacts. Development of the vast oil shale resource within the United States must be accomplished with consideration to the impacts such development will have on the environment. Those factors include oil shale developments impact on air quality, land disturbance, water use and quality, wildlife, and others.

A great deal of environmental analysis on oil shale development has taken place including the Oil Shale Prototype Leasing Program (1970's) and most recently, the DOI BLM's Programmatic EIS on the oil shale region of the western United States. This paper will synthesize these and other analyses to provide a comprehensive description of environmental considerations related to the development of oil shale.

Air quality considerations include the release of oxides, carbon dioxide, particulate matter, and water vapor. Commercially available stack gas clean-up technologies currently in use elsewhere should be effective in controlling oxides and particulates emissions. Carbon dioxide (CO2) will be produced in large quantities and may need to be captured, used in other commercial applications, or otherwise sequestered.

America's best oil shale resources are highly concentrated in several major deposits in Colorado, Wyoming and Utah. The footprint that an oil shale industry would have in this region would be ~31 square miles per MMBbl/d of shale oil. This paper will consider the land disturbance of surface mining, underground mining, in-situ production, other surface impacts, and spent shale. Surface and groundwater impacts will also be assessed.

Environmental control technologies have advanced to improve efficiency, and reduce or better control effluents and emissions. Companies have implemented sophisticated environmental management systems that are incorporated into project development and plant management and operations. This paper will consider all of the potential impacts on the environment posed by oil shale development as well as how existing and emerging technologies are addressing these concerns.
Cognitive Errors in Estimation: Does Anchoring Cause Overconfidence?
Authors: Heywood-Smith A. B. , Welsh M. B. , Begg S. H.
Published: September 2008

Tversky and Kahneman [1] described the biases known as anchoring and overconfidence, respectively, as: the tendency of people to base estimates on any number just seen; and the tendency of people to provide too narrow ranges when estimating the range that an uncertain value might fall within. They also suggested that anchoring might be causing overconfidence if people start by working out their best guess and then adjust from there to get the end points of their range – such that the best guess acts as an anchor. This has passed into the management literature as fact [2, 3] but research on this relationship is actually mixed [4, 5]. This previous research has, however, focused almost exclusively on decision makers making decisions significantly different from those that they normally would.

We present results of a study of 56 oil and gas personnel, designed to demonstrate whether or not anchoring and, specifically, best guesses, cause overconfidence in people when responding to technical scenarios of the sort they might encounter in their real-life roles. These results indicate that having the expert participants give a best guess prior to estimating ranges they were 80% confident would contain the true value (sourced from open access field data) did increase overconfidence as Tversky and Kahneman predicted. Externally provided anchors, however, are shown to have potentially equally strong effects on overconfidence due to their ability to shift the entire range upward or downward. Expertise in regards to the specific parameters being assessed was not found to be related to bias susceptibility.

Finally, we discuss these results, with particular focus on the differences between this study and previous research and how this might account for our different findings, and its implications for confidence interval elicitation and uncertainty representation within the industry.
The Impending Expertise Crisis: New Technology Comes to the Rescue
Authors: Irgens Morten
Published: September 2008

Description of the Material

While Information and Communication Technology (ICT) is a key enabler of productivity, it is not applied evenly along the information value chain that starts with the capturing and transformation of data into information into analytical models and into decisions. The application of automation drops steadily along the chain, which is unfortunate since it is at the analytical and decision levels where industry specific domain knowledge is needed, in other words where highly experienced knowledge workers, petrotechnical and operational expertise that are increasingly in short supply are needed.

The examples are many, for instance in geological modeling, reservoir planning, reservoir management, and operations planning and management. For instance, making day-to-day rig fleet decisions to meet several key performance goals (such as minimizing rig movements and costs while maximizing utilization and time to market) needs expertise and long-earned experience but still cannot be done well using a manual approach. Still, computerized decision support is almost non-existing.

Application

Recent advances in optimization and artificial intelligence technologies make it possible to support many of the industry's knowledge workers in their tasks, support the most experienced to get more work done with more confidence, and empower the less experienced to tackle tasks that otherwise would have been beyond their capabilities. In operations, they promote decisions complex, dynamic situations that are aligned with key performance goals, and show tangible value of operational decision-making in real time.

Results, Observations and Conclusions

There are many convincing examples both outside and inside the oil and has sector that show reduced planning times, reduced response times, improved work processes, reduction in operational errors, improved "what-if" abilities and decision-making, reduction in operational cost, and increased expected production.

Significant New Contributions

The new technologies and their use in decision support systems increase the productivity of knowledge workers.
Initial State of Stress: The Key to Achieving Long-Term Cement-Sheath Integrity
Authors: Saint-Marc Jérémie , Garnier André , Bois Axel-Pierre
Published: September 2008

Cement sheath design has been undergoing very deep changes for the last five years, mainly thanks to Carbon Capture and Storage (CCS). Indeed, for this application, Operators will have to demonstrate to national regulators that cement sheath can provide zonal isolation not only during the operational phases, but also during another phase: the long term storage. Stakes are as big as the market is, covering CCS plus traditional Oil and Gas market, where harmless operations to the environment know-how has become decisive to open new business opportunities.

To ensure zonal isolation, cement system should be properly designed. It should be correctly placed to ensure it is hardening as per designed. Finally, its mechanical properties should be in adequacy with the successive operations the well is submitted to. Many years dominated by rules of thumb to evaluate cement sheath damage have progressively been replaced by engineered methodologies implemented in software. They can be numerical or analytical based, dealing with mechanics of solid or porous media. What should matter are not their pros or cons, but the correct assessment of their limitations to appreciate simulation results.

To evaluate stresses a material can withstand before failure, constitutive laws and failure criteria are necessary but not sufficient: Initial state of stress is mandatory as it sets the initial distance from failure. After presenting the state of art and its weaknesses to evaluate cement sheath initial state of stress, this paper presents Total's methodology based on porous mechanics where initial state of effective stress results from cement hydration evolution with time under downhole conditions. The final state of stress is the consequence of the initial state plus additional stresses from operations. This methodology has been implemented in Total's dedicated software and has been successfully applied to design cement sheath on various operations worldwide: One detailed in this paper.
Artificial Lift Optimization in the Orito Field
Authors: Williams Sandy , Rozo Rafael , Aya Fernando Pérez , Salazar Hernández José Ismael
Published: September 2008

The Orito field located in the South of Colombia, near the Ecuadorian border has been in production since 1967 and is operated by the Colombian state oil company, Ecopetrol (originally discovered and exploited by Texaco). Petrominerales signed an Incremental Production Contract agreement in April 2001 to participate with Ecopetrol in increasing production from the field. Under the terms of the agreement Petrominerales invest 100% of any development activity in return for a portion of the value of the incremental production.

The Orito reservoir is a multi layered reservoir with three production intervals: Pepino, Villeta and Caballos at depths of 3000 ft TVD and 7000 ft TVD respectively. The reservoirs are depleted and pressures are below the original bubble point pressure. The wells can exhibit a number of challenges for production of fluids using artificial lift including: scale; solids production; high GOR; early high water production; and also very high CO2 (80%). Solids issues are exacerbated on wells where hydraulic frac jobs have been performed, which have resulted in a number of premature failures (less than 14 days) of ESP systems.

Artificial lift has been applied to the field and most lift methods have been tried at some point including Electric Submersible Pumps (ESPs), Rod Pumps, Gaslift, Jet Pumps and Progressing Cavity Pumps (PCPs). This paper will: identify the challenges associated with each lift method in this operating environment; present a lift method selection philosophy; provide details of a pilot program to convert Gas lifted wells to rod pump and; document the key steps taken to evolve an ESP design capable of producing the solids from the fractured wells.
Optimizing Injection Intervals in Vertical and Horizontal Wells for CO2 Sequestration
Authors: Kumar Navanit , Bryant Steven L.
Published: September 2008

Storage in deep saline aquifers is one of most viable options for sequestering anthropogenic CO2. The choice of completion for injection wells -- fully or partially completed vertical well, length of horizontal well -- has significant effect on the eventual trapping of CO2 as well as its potential for leakage. Thus optimization of the completion for a target injection rate can help maximize trapping. The density difference between CO2 and in-situ brine influences the optimization because it causes the pressure difference between wellbore and formation to vary with depth in a CO2 injection well. For a long completed interval in a vertical well, the flux distribution is therefore not uniform. Reinforced by relative permeability effects, this can cause deeper perforations to contribute less to the injection rate. In extreme cases only a fraction of the perforations contribute to injection. The degree of non-uniformity depends on the injection rate. The nonuniformity in turn reduces residual phase trapping because less volume of rock and brine comes in contact with CO2.

Field scale compositional reservoir simulations are carried out to study the plume behavior and CO2 trapping under different injection strategies. A semi-analytical algorithm is discussed to determine the optimum interval of injection. For horizontal wells two competing effects, trapping along the well length vs. trapping along the transverse direction, determine the optimum well length. These effects can be correlated to the dimensionless gravity number during injection. Injection at bottom of aquifer results in better trapping and lower leakage potential. For a given rate, the perforation interval can be calculated so that all the perforations contribute throughout the injection period. In a horizontal well, longer well length increases the trapping in direction of well path but reduces trapping in the transverse direction. Consequently, the benefits of a strategy to maximize injectivity may be offset by the disadvantage of less CO2 entering secure modes of storage.
Distributed Temperature Sensor Measures Temperature Resolution in Real Time
Authors: Hadley M. R. , Kimish R.
Published: September 2008

Fiber-optic distributed temperature sensors (DTSs) are used increasingly in the oil and gas industry to provide temperature logs in real time. Often, users need to know the temperature resolution—the noise level on the measured temperature trace. Temperature resolution can be difficult to specify because it depends on many factors, including averaging period, fiber length, excess attenuation from connectors and splices, and hydrogen darkening of the fiber. To overcome this difficulty, we developed a novel technique to enable the DTS to provide an estimated temperature-resolution trace to accompany each temperature trace. We modeled the noise generated by an optical receiver as constant background noise plus signal-dependent shot noise; parameters of this model were readily measured during system tests. Because the DTS measures the Stokes and anti-Stokes signal level at each point along the fiber, we were then able to calculate the corresponding noise at each point. We modified the subsequent data processing that calculates temperature from these signals to handle a Gaussian model (μ, σ) instead of a single-valued signal. The resulting output provided an estimated temperature-error trace point-by-point along the fiber to accompany each temperature trace. Being derived from the optical signal levels rather than from statistics of the measured temperature, the estimate is not affected by the actual temperature varying with time or along the fiber. However, changes in signal level resulting from changing fiber loss immediately affect the error trace, giving a real-time indication of measurement quality. We have validated the technique against actual temperature noise measurements using a resolution test rig we designed for the purpose. We found good agreement between the estimated and measured temperature resolution, over a range of operating conditions. This new technique, by providing temperature error bounds based on conditions obtaining at the time of measurement, will enable the performance of a DTS to be continuously monitored and will give temperature analysts the information needed to determine the confidence levels of their temperature log interpretations.
Polymer Injection in Deep Offshore Field: The Dalia Angola Case
Authors: Morel D. , Vert M. , Jouenne S. , Nahas E.
Published: September 2008

Whereas on-shore polymer injection may be qualified as a mature EOR technique, considering the hundreds of operations that have been conducted all over the world, only one polymer pilot has been implemented offshore, and none in deep offshore conditions.

A very thorough feasibility study of polymer injection has been made on the Dalia field in Angola, a typical deep-offshore high permeability (>1D as an average) sandstone reservoir containing medium viscosity oil (3 to 7cP under reservoir conditions).

The study has demonstrated that high molecular weight hydrolyzed polyacrylamides could be used under a wide range of salinities covering sea water and a mixture of sea water and produced water.

Additional recoveries in the range of 3 to 7 % can be expected in this particular context of large well-spacing development of a medium viscosity field.

Powder polymer supply is achievable for deep offshore fields either with a specific bulk carrier or using standard international containers to transport big bags (750 kg).

Although the on-deck option is simpler, even in the case where no room is left on the existing FPSO, marine options can be found to safely process the polymer on a barge connected to the FPSO (depending on the sea conditions), but the on-deck option is more simple.

The need for an injectivity pilot is compulsory to demonstrate the operability of the facilities, and the injectivity of the polymer solution. A single well test has been designed and is planned fall 2008 in Luanda on one of the well of the Camelia reservoir.

A skid dedicated to the injectivity test has been designed, assembled and constructed to prepare a mother solution of polymer from powder. Tested in France (no injection), the skid has been shipped to Luanda for installation on the FPSO during summer 2008.

Future of the project will depend on the injectivity tests results and on-going studies on a phased approach.
Production Data Analysis of Shale Gas Reservoirs
Authors: Lewis Adam M. , Hughes Richard G.
Published: September 2008

Unconventional shale gas reservoirs have become a very important part of the resource base throughout the world, but especially in the United States. Production data analysis techniques using various forms of material balance time originally put forth by Palacio and Blasingame (1993) have been proposed and validated in recent publications for a variety of problems (including shale gas and coalbed methane systems) using an adjusted system compressibility function similar to that proposed by Bumb and McKee (1988) to account for adsorbed gas. These modified material balance solutions allow for "type curves" (rate or pressure solutions) to be used in a conventional analysis manner.

The significant challenge in the application of production data analysis for shale gas systems is to determine what the parameter values (analysis results) represent within the context of the inherent complexity of these systems. In this work we propose a slight (but substantive) modification to material balance time and apply the technique to synthetic and field data to assess the capability of this approach for the analysis of production data from gas shales. The formulation we use is that of Cox, et al. (2002) which provides a means for evaluation production data as an equivalent "well test", where we are able to observe characteristic flow regimes in the data and constrain several of the key parameters of interests in shale gas systems. While the field results are difficult to corroborate, the relative magnitudes of the parameters we obtained appear to be reasonable.
Oilfield Trainees Benefit From PDA-Based Applications
Authors: Hughes J. A. , Martin R. , Guerrero J. V.
Published: September 2008

Training departments in today's oilfield industry are faced with the challenge of equipping new employees with the ability to lookup technical information and to perform accurate, routine calculations in a short period of time. Traditional methods include classroom instruction for a group of students who follow along with a personal computer or hardcopy manual. Hardcopy manuals are relatively inexpensive to produce in large quantities, but they are a bulky resource to carry around after the course. Personal computers and laptops are powerful tools, but a plan to assign laptops to individuals or to dedicate a number of computers to a classroom may be cost prohibitive.

Another tool that is becoming more popular is the PDA or PDA-phone. As portable as a cell-phone, powered by a PC-like operating system, and at a cost somewhere between those two cousins, the PDA has gained the attention of trainers and students. Teaming the training department with the software applications group, a plan was conceived to improve and customize an oilfield PC application for use on a PDA. Once that plan became a project, a search began for other, existing PDA software applications that could be useful in the oilfield.

This paper follows the success of one software application that was made available for both PC and PDA, and how students were empowered to give quick, accurate answers to common, difficult questions – with the tap of a stylus. It also outlines the direct benefits to the training department, trainees, employer, and ultimately to the customer. Finally, the paper evaluates the cost-benefit of PDA ownership and the potential for other applications or information to be made available for the PDA.
Evaluation of Reservoir Connectivity and Development Recovery Strategies in Monument Butte Field, Utah
Authors: Wang Jianwei , Abiazie Joseph , McVay Duane A. , Ayers Walter B.
Published: September 2008

Monument Butte field produces oil from 22 commingled sandstone reservoirs across a 2200-ft interval of the Green River formation. Total (primary and secondary) recovery is less than 10% of the OOIP. Green River formation sands are lenticular, lacustrine fluvial-deltaic units that have limited aerial extent and vertical communication, resulting in poor interwell connectivity. Moreover, the reservoirs sands have low permeability. To determine interwell connectivity and to identify methods to improve oil recovery, we conducted detailed reservoir characterization and simulation studies in a pilot area of Monument Butte field.

We built a 3D geostatistical model and ranked geological realizations using production history matching with streamline simulation. Detailed petrophysical and geological modeling were used to quantify interwell connectivity of sands as a function of well spacing. Studies of interwell connectivity were also used to identify flow barriers that we applied in upscaled reservoir simulation models to better represent interwell connectivity. A combination of manual and assisted history matching methods was used to calibrate the reservoir model. Primary, secondary, and tertiary development strategies were then evaluated for future optimization of oil recovery for new developing areas in Monument Butte field.

This study yielded a reservoir model much improved over those of previous studies. A good history match was obtained for most wells, despite the complexity of this stacked, heterogeneous reservoir system. Simulation results indicate that interwell connectivity has the greatest impact on reservoir performance. Interwell connectivity was demonstrated for only major sands, and interwell connectivity increases as well spacing decreases for these sands. A pilot 20-acre infill drilling study is needed to verify this conclusion. The overall connectivity for the combined 22 zones is 0.056 (connected adjacent well pairs divided by total adjacent well pairs). The connectivities for major sand zones evaluated by history matching are 0.65, 0.16, 0.23, and 0.01 for the D1 sand, C sands, A sands, and LODC sands, respectively. Simulation results indicate that reservoir performance can potentially be improved with various reservoir management strategies, including infill drilling. For new development areas, water flooding should start as soon as possible (within 6 months). Tertiary recovery methods may have potential in the Monument Butte field, given the low recovery efficiencies for primary and secondary recovery. Water-alternating-CO2 injection appears to be superior to other tertiary recovery methods. Further evaluation and piloting of tertiary methods is required, given the connectivity risk. The target area study results can be used to guide the development of other parts of the large Monument Butte field.
Dynamic Decision Trees as an Alternative for Real Options Valuation
Authors: Galvis C. F. , Bravo O.
Published: September 2008

This paper suggests a model to incorporate Real Options Valuation (ROV) to the decision-making process concerning E&P projects, through a robust, flexible and innovative technique: Dynamic Decision Trees (DDT). The proposed approach integrates Discounted Cash Flow (DCF), Decision Trees and Montecarlo Simulation into one practical methodology much easier to utilize and understand than the traditional binomial lattices. The DDT model is presented using as framework the valuation of developing the Sardinata field in Colombia.

Given that the Net Present Value (NPV) of the Discounted Cash Flow associated to the project was negative and close to break-even, the decision to execute it was delayed, despite management's good feelings regarding production potential and high oil prices. However, by modeling the project via DDT, it was possible to calculate the value inherent in project's uncertainty and managerial flexibility, allowing decision-makers to apply the Real Options concept and make better informed decisions. Consequently, the decisions to obtain 3D seismic and drill 25 infill wells were triggered.

Real Options are a direct extension of Financial Options, as well as its most common valuation methods. Therefore, the assumptions upon which this theory is built must also apply for Real Options Valuation. However, this does not occur when using these valuation methods in highly risky projects such as those of the Oil & Gas Industry. The authors offer an alternative solution for valuing real options in E&P projects, yet still complying with the assumptions that support the theory.

Through the use of DDT it was possible to avoid limitations in volatility estimation and option valuation, leading to a far-reaching and more accurate application of the theory. DDT proved to be a simpler, more robust, and more flexible manner for valuing real options than the traditional binomial lattices when dealing with E&P projects.
Best Practices in Designing HP/HT Cement-Plug Systems
Authors: Syed Haidher
Published: September 2008

Cement plugs are required mainly to abandon a well or zones or to kick off new drilling or completion efforts. Almost all ultra-HPHT exploratory wells and all other non-producing wells (which have ended their useful life) require abandonment with cement plugs.

Cement plugs for HPHT and ultra-HPHT application require conform to the acceptable fluidity, ultimate strength and desired properties. The placement environment exacerbates the challenges of system design, especially if the well is deviated or approaches horizontal.

Achieving successful cement plugs in highly deviated or in horizontal wells in HPHT and ultra-HPHT conditions, especially in brine environments, requires special designs and techniques. The requirements include modified testing procedures and products that can withstand bottomhole pressure and temperature conditions for the entire life of the well. Furthermore, setting a cement plug downhole in a deviated HPHT well may require special equipment and logistics.

As an example of the complications in HPHT wells, on the east coast of India bottomhole static temperatures are as high as 507°F and mud weight can vary between 14 and 19 ppg in deviated wells. Experience has shown that conventionally calculated bottomhole circulating temperature alone is inadequate to determine the working temperature downhole. However, with the help of computer-aided temperature simulation and all the above techniques, many successful cement plug jobs have been executed under these difficult conditions.

Using case histories for illustration, this paper will share best practices developed from 4 years of experience designing and placing cement plugs in 8 HPHT and ultra-HPHT wells successfully. These practices will include HPHT cement plug design considerations, modified lab testing procedures, special placement techniques and product choices.
Sustainable Spatial Architecture for Geo Engineering Data and Workflows
Authors: Kozman Jess , Ripley Thomas
Published: September 2008

Spatial attributes are pervasive in petroleum engineering data. Solutions that create a competitive advantage by effectively using this data require a sustainable architecture with documented workflows to increase user confidence and alleviate engineering risk. The components of a sustainable spatial architecture are; data accessibility, a standard data model, portal consumption and Geographic Information System (GIS) access, and data maintenance and business rules. A full lifecycle solution for management of spatial attributes includes collection from field and public domain sources, quality assessment and control, storage in standardized data models, distribution to analysis applications, and capture in knowledge management and audit systems. Each component and lifecycle stage can impact financial performance of the organization using the geotechnical data. Site assessments and a standard methodology for documentation of processes and components were used to compare solutions and value statements for multiple domestic and international operators.

The assessments found that accessibility by end-users impacts quality, accuracy, and confidence related to spatial data. The economic impact of this component is lack of end-user confidence in data tools, and the cost of re-acquiring data. The data model provides feature class intelligence, naming conventions, and attribute accessibility, a standard taxonomy, and a method to move petroleum engineering data into a world of points, lines and polygons. The utility of this component is measured in lost opportunity costs of incomplete analysis, and inconsistent data causing poor drilling decisions. Portal access through service oriented architectures delivers visual and automated quality control of multiple data sources and is documented to save engineering time spent on data discovery and manipulation. Business rules serve to formalize data ownership and governance and support an intelligent synchronization process that maintains validated corporate spatial data, providing a single source of truth that reduces risk for engineering decisions.

Successful solutions require all described components plus repeatable and auditable workflows for extracting well, reservoir and seismic spatial attributes from robust industry standard models. This study allows petroleum engineers to determine the maturity of their current and legacy solutions, and plan for goals of mitigating risk, improving workflows, and lowering costs within a scalable, sustainable Spatial Data Architecture.
A New Solution to Restore Productivity of Gas Wells With Condensate and Water Blocks
Authors: Bang Vishal , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R. , Ahmadi Mohabbat
Published: September 2008

During production from gas condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near the wells. This adds significantly to the total liquid blocking.

Experiments were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and increases the gas relative permeability.

The increase in gas relative permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative permeability by a factor of about 2 were observed. The alteration of wettability after the chemical treatment was evaluated by measuring the USBM wettability index of treated reservoir cores. Measurements show a significant amount of the surfactant is adsorbed on the rock surface, which is important for the durability of the treatment.

Many attempts have been made to develop effective chemical treatments to mitigate the damage caused by condensate and/or water blocking with little success until now under realistic reservoir conditions. Using inexpensive, safe and effective solvents was one of the keys to the success of our new approach. Others have mostly tried reactive materials that are subject to complications in downhole applications. We use a non-reactive, nonionic polymeric surfactant that does not have any of these problems and is robust over a wide range of temperature, pressure, permeability and brine salinity.

We have developed a chemical treatment for liquid blocking that shows great potential to increase production from gas condensate wells. Compositional simulations indicate the economics of this treatment process are likely to be very favorable.
Investigation of Economic Incentives for CO2 Sequestration
Authors: Ghomian Yousef , Urun Mehmet , Pope Gary A. , Sepehrnoori Kamy
Published: September 2008

We have completed an exploratory economic analysis based upon systematic compositional simulations of CO2 EOR to establish how much and what type of economic incentive might be needed to encourage oil companies in the U.S. to store CO2 in oil reservoirs. The economic analysis took into account factors such as capture and transportation costs. In order to quantify the effect of flood performance, various simulations were performed by employing different reservoir types, well spacing, and injection schemes. Experimental design and method of response surfaces along with Monte Carlo simulations were utilized to perform this study in a systematic, efficient and accurate manner. Combinations of reservoir parameters and economic factors were studied to achieve comprehensive understanding of the financial performance of coupled CO2 sequestration and EOR projects. Possible CO2 credits were also quantified in a probability based distribution functions considering various uncertain economic and geologic characteristics in different projects.
A New Method of Well-Test Analysis in Naturally Fractured Reservoirs Based on Elliptical Flow
Authors: Igbokoyi Alpheus O. , Tiab D.
Published: September 2008

Well test analysis in naturally fractured reservoirs is generally based on the radial flow model, even when it is widely believed that such reservoirs are anisotropic. The radial flow model is however only applicable to purely homogeneous system and long time solution. It cannot provide a complete formation analysis in a reservoir that exhibits anisotropy.

This study therefore presents a new method of estimating permeability anisotropy in naturally fractured reservoirs. Maximum and minimum permeability are obtained in one well test. The maximum permeability is attributed to the large scale fractures in the system while the minimum permeability may be due to the small scale fractures orthogonal to the large scale fractures. In a situation where the fractures are orienting in one direction, the minimum permeability will reflect the matrix permeability. The type of flow path developed (narrow or wide flow path) can also be predicted. This is useful in predicting the direction of fluid flow.

Application was made to four field examples, one of which was an interference test. The interference test was used as a validation process. The results obtained are in agreement with that of a conventional interference test method of analysis.