bluuebunny/crossref_metadata_2025 huggingface dataset:
Determination of Fluid Composition Equilibrium under Consideration of Asphaltenes – A Substantially Superior Way to Assess Reservoir Connectivity than Formation Pressure Surveys
Authors: Pfeiffer Thomas , Reza Zulfiquar , Schechter David S. , McCain William D. , Mullins Oliver C.
Published: October 2011

Assessing reservoir connectivity during the earliest stages of reservoir evaluation is highly desirable for successful field development. Static pressure measurements with wireline formation testers have been used to assess compartmentalization; if two permeable zones are not in pressure communication, they are not in flow communication. However, the presumption that pressure communication implies flow communication has repeatedly proven to be incorrect. Pressure equilibration requires relatively low mass flow compared to fluid composition equilibration. Thus pressure communication does not impose a stringent condition on connectivity. In contrast, fluid composition equilibration requires mixing of the entire content of the reservoir. Fluid composition equilibration provides a correspondingly much more rigorous set of conditions to determine connectivity.

In this paper, a comparison is made between the time constants for pressure versus fluid composition equilibration for identical reservoir parameters. A reservoir model is designed to simulate numerically equilibration processes over geologic timescales at isothermal conditions where diffusion and gravity are the active mechanisms. A variety of initial conditions and reservoir fluid types are considered. The fluid component with the largest molecular weight and volume is expected to have the longest equilibration time. For black oil, this work accounts for asphaltene nanoaggregates in their own component group. The results are compared with analytical calculations. Longer equilibration times correspond to tighter constraints on connectivity.

Fluid composition equilibration is seen to constrain connectivity by 6 or more orders of magnitude beyond pressure equilibration. The equilibration time of the asphaltenes nanoaggregates exceeds the the compositional equilibration of all other fluid components by a factor of five.

Only a process that stretches across the entire age of the reservoir is likely to capture geologic events that cause compartmentalization. Consequently, the evaluation of the distribution of fluid compositions is shown to be a far better method to test for connectivity than pressure communication. Determination of fluid equilibrium should become part of the standard procedure for reservoir connectivity evaluation.
Positive Displacement Motor Innovation Drives Increased Performance with PDC Bits in 8¾-in. Hole Size
Authors: Azizov Azar , Davila Wilfredo , Nnanna Obi , Rizen Andrej , Scott Dan
Published: October 2011

With the introduction of a new, wear-resistant polycrystalline diamond compact (PDC) bit cutter technology in recent years, the demand for increased torque output from the positive displacement motor (PDM) has dramatically increased. The commercial introduction of pre-contoured (i.e., equidistant rubber thickness) stators in 2000, solved the theoretical technical challenge of developing very high torque output in a PDM. Yet, in cost-sensitive land-based drilling markets where conventional power sections are still a major factor, the requirement for traditional motor power section construction restricted the rate of penetration improvements.

Recent developments in the chemistry of the standard stator elastomer have enabled a step-change improvement in the performance and durability of the power sections in PDMs. This premium elastomer, manufactured in conventional stator cans, can generate higher differential pressure and subsequently more torque, while achieving increased durability, even in some of today's oil-based drilling environments. This higher level of torque and increased downhole durability is ideally suited for the increasing toughness and aggressiveness of today's premium PDC bit. This paper will review in detail this innovative motor technology, describe how it enables higher performance levels, and present several case histories illustrating this performance enhancement.
Evaluation of Well Testing Systems for Three Deepwater Gulf of Mexico (GOM) Reservoir Types
Authors: Millheim Keith , Williams Thomas E. , Yemington Charles R.
Published: October 2011

A major RPSEA ultra-deep water (UDW) strategic theme is early appraisal of a reservoir with minimum drilling in order to reduce the risk associated with planning an economic reservoir development. Deepwater well testing in the Gulf of Mexico (GoM) is not economically viable or practical, primarily due to the high cost of conventional equipment and environmental and safety risks.

This paper discusses the results of a research project co-funded by Research Partnership to Secure Energy for America (RPSEA) & Industry "EARLY RESERVOIR APPRAISAL, UTILIZING A WELL TESTING SYSTEM" which incorporated a study utilizing historical deep water production data to show the need for conducting well testing in most Gulf of Mexico (GOM) reservoir discoveries. The project took reservoir data from three major deep water plays. The project analysis and evaluation included eight deep water well testing systems for subsea wells in the Gulf of Mexico (GOM). From the reservoir data sets a complete series of simulated well tests were run: short term and long term tests, interference tests, and injection tests. Also, nodal analyses of the various simulated tests were done. The first part of this paper presents the results and a summary of the analyses.

The reservoir modeling led to the design of eight well testing systems that can be used for short-term, long-term, interference, and injection testing. Each system was analyzed for operational feasibility in reference to subsea and surface safety systems, and vessel requirements, with the focus of reducing risks to personnel, the environment, equipment, and complying with all applicable regulations.

This paper provides a general oversight to the various well tests. The well test system architectural designs and operational feasibility analysis give all the available options for deep water well testing in regards to downhole, subsea, surface, and vessel requirements, with an extensive focus on safety requirements. Providing this information to industry professionals and operators allows for more accurate decisions when justifying the production capacity and commerciality of a field / reservoir.
Production Characteristics of the Bakken Shale Oil
Authors: Tran Tan , Sinurat Pahala , Wattenbarger R. A
Published: October 2011

There are three main types of well production trends in the Bakken formation. Each decline curve characteristic of these production trends has an important meaning to the production trends of the Bakken Shale play especially type I and type II production trends. In the total of 146 well histories, there are 51 % of wells in Type I production trend. This high percentage of Type I production trend is showing the true characteristic of the Bakken Shale reservoir, which will be discussed later in this paper. Type I production trend has the reservoir pressure drops below bubble point pressure and gas releasing out of the solution. This can be seen on the GOR curve vs. time plot. The cause of reservoir drop below bubble point has been analyzed, and the production of oil in this behavior has driving force from the solution gas. In additional, two linear flow regimes have been observed by looking at the log-log plot of rate against time plot of type I well.

In a type II production trend, production is primary from the matrix. Reservoir pressure is higher than the bubble point pressure during the producing time and oil flows as a single phase throughout the production period of the well. GOR curve is almost constant during the production period. A single linear flow behavior is observed in Bakken Shale play of type II wells. This behavior is characterized by a half-slope on the log-log plot of the oil rate versus time plot.

A type III production trend typically has scattering production data from wells with a different type of trends. It is difficult to study this type of behavior because of scattering data and it will lead to uncorrected interpretation for the analysis.

Calculation procedures are given for OIIP estimation, and the area of matrix drainage between fractures, Acm.
Anomalous Pore Pressure and its Relation with In-Situ Stress Regime in Deepwater Play
Authors: Li G. , Allison D. , Bai M.
Published: October 2011

Drilling is more challenging when the pore pressure is anomalous because it is higher or lower than the normal hydrostatic pressure for a depth of interest. This study is based on a review of pore-pressure analysis of more than 100 deepwater wells in the Gulf of Mexico (GOM). The intent in reviewing the data was to define what area/depth and conditions create the greatest risk of anomalous pore pressure. Both geological and geomechanical factors, such as salt structure and in-situ stress regime, were considered to determine the underlying cause. Overcompaction from tectonic forces or salt structures was identified as a key factor in generating anomalous pore pressure. By studying the combination of different sets of log measurements, such as gamma ray (GR) sonic travel time (DT), resistivity (RES), and density (RHOB), each anomaly related to pore-pressure distribution was examined in more detail, reviewing the circumstances under which the anomalous pore pressure occurred and, whenever possible, identifying the underlying cause.

Through a better understanding of the relationship between pore pressure and in-situ stress, an improved methodology for predrill pore-pressure and fracture-gradient prediction for deepwater wells has been developed. Normalized stress data trends, including both pore pressure and in-situ stresses from different GOM regions, were plotted as a tool to compare the relationship between the pore pressure and in-situ stress regime. The coupling effects between pore pressure and in-situ stress outline best-practice methodology for defining anomalous pore pressure across the GOM. The solution can lead to an effective approach to detecting anomalous pore-pressure distribution, which is particularly important when deepwater drilling because the operating safety margin decreases as the water depth increases, and there is also an urgent need in stimulation to have more knowledge and control of the prediction process for pore pressure.
Discretization, Simulation, and the Value of Information
Authors: Bickel J. Eric
Published: October 2011

Most decision analyses include continuous uncertainties (e.g., oil in place, oil price, or porosity). Analysts are frequently concerned with how to best structure, compute, and communicate decision models under these circumstances. While decision trees are well suited for discrete random variables with a few possibilities, they become unmanageable for a large number of outcomes. To address this concern, analysts frequently use discrete approximations such as Swanson's Mean. In this case, one approximates a continuous probability distribution by weighting the P10-P50-P90 fractiles by 0.30-0.40-0.30. Unfortunately, this method, and others like it, significantly underestimate the mean, variance, and skewness of most distributions—especially the lognormal, where its use is common. In this paper, we compare different discretizations within the context of a value of information problem and document the degree of error induced. We find that the best discretization is dependent on the decision context, which is difficult to specify in advance. In addition, we contrast the use of discrete approximations to Monte Carlo simulation, which many view as being more accurate. One must keep in mind, however, that simulation induces sampling error, while discretizations induce approximation error. The question is how many Monte Carlo (MC) trials it takes such that these two errors are equivalent. We find that it takes thousands, perhaps tens of thousands, of MC trials to provide better results than simple discretization methods. This is quite important if one is using MC in connection with a model that takes a long time to compute a single realization.
Magnetic Resonance Utilization as an Unconventional Reservoir Permeability Indicator
Authors: Bray Jim , Smith Charles H. , Ramakrishna Sandeep , Menendez Eliud
Published: October 2011

Unconventional reservoirs require unconventional solutions. Horizontal drilling into these reservoirs followed by intensive perforating and fracture treatment techniques have been the accepted standard for producing these wells. The general thought process was that the closer these perforations could be placed and treated, the greater the production rates.

Recent papers that show the results of production logs in the horizontal sections of these wells present a dilemma. Even though many different intervals have been attempted in the wells, only one or two of the intervals in each well are actually producing—either the completions are ineffective, or the production logs are suspect.

In addition, data published recently also show the plastic nature of these unconventional reservoirs. In one study, the rock was placed in three-dimensional stress conditions and then perforated. Within 48 hours, the perforation tunnel had closed off, eliminating the ability of fluids to migrate to the well, which could also be a source of decreased production. A technique was required to find intervals of the well that could support open perforations to maintain contact of the formation to the well.

Magnetic resonance imaging logs were added to the logging program to establish additional parameters that could be used for reservoir description. The Bray-Smith equation, which has been used for several years to describe permeability, was used as a base for adjustments. The observation for the relationship of the bin-size definition to permeability was established through laboratory NMR work. The algorithm was adjusted to apply specifically to unconventional reservoirs. We have already used this relationship to select additional intervals for perforation and treatment and have eliminated other sections that would have been completed under the previous completion programs.

In this paper, we present the base case for this relationship and establish the general relationship between bin size and unconventional permeability. We expect to publish conclusive relationships of unconventional reservoir permeability to production rates as we acquire a history of data.
Reservoir Forecast Optimism – Impact of Geostatistics, Reservoir Modeling, Heterogeneity, and Uncertainty
Authors: Meddaugh W. Scott , Champenoy Nicole , Osterloh W. Terry , Tang Hong
Published: October 2011

The oil and gas industry uses static and dynamic reservoir models to generate production forecasts. Generally, industry look-backs (and informal networking) have shown that forecasts are often optimistic for both "Greenfield" projects with limited data and "Brownfield" projects with abundant data. One of the main sources of optimistic forecasts is biased estimates of the original or net/targeted in place hydrocarbon volume. Some bias is due to sampling, particularly for Greenfield developments, and this bias can be reduced statistically or by use of appropriate uncertainty-based workflows together with a reasonable uncertainty assessment that includes the available data and an appropriate suite of analogs. An underappreciated additional source of significant bias related to in place volumes is the use of a stochastic reservoir property model to locate wells. The use of stochastic earth models combined with well placement optimization workflows is likely to yield significantly optimistic forecasts. Well placement and optimization should be based on property distributions derived via estimation methods such as kriging rather than stochastic methods.

Reservoir models are usually generated using sophisticated software. Elegant geological models can be generated without an adequate understanding of the limitations imposed by the available data, associated uncertainty, or the underlying stochastic algorithms and their input requirements (e.g. the semivariogram; a measure of heterogeneity). For example, forecasts based on models generated using different semivariogram ranges (all other input parameters held constant) show that the recovery factor for waterflooding may be impacted significantly whereas for steamflooding the impact may be negligible. Recent studies using an extensively sampled portion of a heavy oil carbonate reservoir have shown that grid size, which has minimal effect on primary recovery forecasts, will impact forecasts for displacement processes. Generally, if there are fewer than ten cells between injectors and producers in dynamic models, waterflood forecasts and perhaps also steamflood forecasts will be optimistic. The impact of static and dynamic model parameter choices on forecast bias should be evaluated as part of any comprehensive reservoir study.
Hydraulic Piston Pump for Dewatering Gas Wells
Authors: Toby Pugh P. E. , Robison Clark E.
Published: October 2011

A recent operator application required a hydraulic piston pump that could operate from at least 10,000 feet while producing as little as 10 bpd.

The design parameters for this pump were:

Produce 10-25 bpd from at 10,000 feet Operate at speeds down to 4 SPM Eliminate any potential of gas locking Require no more than five horsepower for its operation Be able to use solar panels for the energy source

The engine end from the field proven Guiberson PL-I was chosen for this pump based on its demonstrated ability to operate at speeds down to 4 SPM at depths of approximately 10,000 feet. Unfortunately, the production end of the PL-I is susceptible to gas-locking so it had to be modified in order to prevent that from happening. This is discussed in more detail later in the paper.

This pump can be used as either a free style or a fixed style pump. It is intended to operate in the typical vertical position as well as at inclinations of up to 90 degrees. The BHA is intended to be run in 5-1/2"-23#/ft casing (or larger) with parallel or concentric tubing strings. For installations with 4-1/2" casing, the pump will not be modified but a special BHA will be needed that minimizes the diameter requirements.
Application of Real Rock Pore-throat Statistics to a Regular Pore Network Model
Authors: Sarker M. Rakibul , McIntyre Dustin L. , Ferer Martin , Siddiqui Shameem , Bromhal Grant S.
Published: October 2011

This work reports the application of real rock statistical data to a previously developed regular pore network model in an attempt to produce an accurate simulation tool with low computational overhead. A core plug from the St. Peter Sandstone formation in Indiana was scanned with a high resolution micro CT scanner. The pore-throat statistics of the three-dimensional reconstructed rock were extracted and the distribution of the pore-throat sizes was applied to the regular pore network model. In order to keep the equivalent model regular, only the throat area or the throat radius was varied. Ten realizations of randomly distributed throat sizes were generated to simulate the drainage process and relative permeability was calculated and compared with the experimentally determined values of the original rock sample. The numerical and experimental procedures are explained in detail and the performance of the model in relation to the experimental data is discussed and analyzed. Petrophysical properties such as relative permeability are important in many applied fields such as production of petroleum fluids, enhanced oil recovery, carbon dioxide sequestration, ground water flow, etc. Relative permeability data are used for a wide range of conventional reservoir engineering calculations and in numerical reservoir simulation. Two-phase oil water relative permeability data are generated on the same core plug from both pore network model and experimental procedure. The shape and size of the relative permeability curves were compared and analyzed and good match has been observed for wetting phase relative permeability but for nonwetting phase, simulation results were found to be deviated from the experimental ones. Efforts to determine petrophysical properties of rocks using numerical techniques are to eliminate the necessity of regular core analysis, which can be time consuming and expensive. So a numerical technique is expected to be fast and to produce reliable results. In applied engineering, sometimes quick result with reasonable accuracy is acceptable than the more time consuming results. Present work is an effort to check the accuracy and validity of a previously developed pore network model for obtaining important petrophysical properties of rocks based on cutting-sized sample data
Parametric Analysis of Wellbore Strengthening Methods from Basic Rockmechanics
Authors: Morita Nobuo , Fuh Giin-Fa
Published: October 2011

The authors previously presented the industry's first SPE paper in wellbore strengthening by proposing a new idea for lost circulation prevention while drilling. During our attendance of the 2010 SPE FORUM (Lost Circulation and Wellbore Strengthening) held at Park City, Utah, we presented and discussed about various wellbore strengthening methods as currently employed and practiced in the industry. These methods include well cooling, stress cage, and tip screening of induced fractures. Some participants requested parametric analysis of these methods using equations of rock mechanics principles. A set of analytical equations are developed for parametric analysis of four typical wellbore strengthening methods. They may be classified by the size of cracks to be stabilized as follows:

Borehole strengthening with heating by stabilizing 0 to 0.1 in. cracks. Borehole strengthening by stabilizing micro cracks (with mud cake or fine particles) for 0.1 in. to 1 in. cracks Borehole strengthening by stabilizing macro cracks (stress cage method) for 1 in. to 2 ft cracks Borehole strengthening by stabilizing a large fracture with tip screening method for more than 10 ft cracks Simplified equations are developed for the above four methods. These equations reveal limitations and advantage of each method. The following items are a part of the parameter studies:

Water base mud mixed with 25-40 mesh particles stabilizes borehole by plugging micro cracks with mud cake. Some solid return from shale shaker or mixing 25-40 mesh crushed nut shell enhances borehole stability. The stress cage method is safely applied if the formation permeability is not too small. However, as the permeability is small, it requires to reduce extension of induced fracture with a high fluid loss pill to place the granular materials, while an ultra-low fluid loss mud is required during drilling after strengthening to reduce the pressure build-up in the fracture section behind the seal. The tip screening method does not require squeezing particles by inducing a fracture. Particles mixed with drilling fluid prevent fracture initiation, and, if a fracture is induced, it prevents further fracture propagation by tip screening. It is effective if a lost circulation zone has some permeability, while it is not effective if the lost circulation zone has no permeability.

In this paper, a set of simplified equations are presented to clarify the wellbore strengthening methods and parameter studies are conducted for each method to clarify the advantages and disadvantages of each method. Equations developed in a previous paper by current authors are significantly improved for easier implementations of wellbore strengthening methods.
A CO2 Sequestration Simulation Case Study at the Dickman Field, Ness Co., Kansas
Authors: Liner C. L. , Geng P. , Zeng J. , King H. , Li J
Published: October 2011

Since 2006 the University of Houston has evaluated CO2 sequestration potential in a deep saline aquifer system in Ness County, Kansas. This paper is a summary on the simulation part of the project.

Combining 3D seismic and dense well control, a static model was constructed and history matching was accomplished.Good history matching validates the static geological model and the same model can then be further used for CO2 sequestration prediction.

After history matching, several aquifer simulation models were constructed to study the CO2 injection rate and storage safety issues. A full formation simulation model including sallow geological layers and deep saline aquifer was further constructed to predict CO2 migration after injection. Free CO2 gas trapped in a geological structure can migrate to the surface through faults, fractures, failed cap rock, or corroded well pipe. These actions represent a real safety threat. A major challenge is to develop a practical simulation model to study CO2 leakage scenarios over long time periods (typically 250 years in our work). One way of improving CO2 storage safety is to accelerate residual gas and solubility trapping. Our simulation results indicate two effective ways of reducing free CO2: injecting CO2 with brine, and/or horizontal well injection. In the carbonate aquifer we studied, tuned combination of these methods can reduce the amount of free CO2 from over 50% to less than 10%.

As part of the lower Paleozoic aquifer system in Kansas, Missouri and Oklahoma, the site under the Dickman oil field shows potential as a viable CO2 storage site. However, faulting and numerous abandoned wells cast uncertainty on its ability to serve as a permanent CO2 storage site. This study shows that a careful simulation study can maximize CO2 injection rate, minimize existence of free CO2, and significantly reduce uncertainty in the safety of CO2 permanent storage.
Use of Data-Driven and Engineering Modeling to Plan and Evaluate Hydraulic Fracture Stimulated Horizontal Bakken Completions
Authors: Shelley Robert F. , O'Connell Kevin E. , Skari David , Baribault Rey A.
Published: October 2011

Drilling horizontally to facilitate hydraulic fracturing is proving to be the well type of choice to develop the low permeability Bakken Shale in the Williston Basin. However, as the complexity of these completions increases (to 30 or more hydraulic fracturing treatments per well), the challenge of modeling these completions and justifying the expenditure ($3 million or more) is becoming more problematic. In addition, there is frequently only limited reservoir data available due to horizontal open hole logging limitations and the fact that the middle Bakken target zone is rarely completely penetrated. In addition to formation evaluation and rock mechanics, other difficult to access issues such as hydraulic fracture geometry, frac staging methodology, perforation methodology, frac compartment zone isolation, drillout/cleanup, wellbore placement/orientation, etc., can also have a significant effect on well production and economics. This presentation will describe a methodology which is being used to improve hydraulic fracture understanding and facilitate decision making pertaining to the completion and stimulation of horizontal Bakken wells. Case histories from the Truax and Wildrose areas in Williams and Divide Counties, North Dakota are used to demonstrate the usefulness of using this type of approach.
Long Term Hydrocarbon Removal Using Treatment Wetlands
Authors: Wallace Scott , Schmidt Martin , Larson Eric
Published: October 2011

This study focuses on the treatment performance of two full-scale treatment wetlands constructed by BP for groundwater remediation. The first is in Casper, Wyoming (commissioned in 2003); the second is located in Wellsville, New York (commissioned in 2008). Treatment wetlands were selected in both cases due to low operating costs, which result in favorable life-cycle costs when managing legacy contaminants associated with former refining operations.

Both treatment systems have been highly effective and have met regulatory compliance objectives. System performance can be measured by a first-order, area-based rate coefficient (k), that can be applied to future wetland design projects. For the full-scale Casper wetland, rate coefficients were measured as 0.66, 0.96, and 0.89 m/d for benzene, BTEX and gasoline-range organics, respectively. The wetland system removes essentially 100% of these constituents, with non-detect concentrations in the effluent.

For the full-scale Wellsville wetland, rate coefficients were measured as 0.37 and 0.33 m/d for aniline and nitrobenzene. The wetland system has removed 94% of the aniline and 93% of the nitrobenzene (based on mean influent and effluent concentration values over the period of record). Treatment performance has been very stable after the initial winter start-up period. Excursions above non-detect concentrations typically occur during the winter months when water temperatures are at a minimum and the wetlands are partially iced over. The Wellsville system has also been very effective in iron removal, removing 98% of the iron (based on mean concentration values), despite relatively high influent concentrations (mean value of 33.3 mg/L).

Both systems operate under cold climate conditions. The Casper wetland operates at temperatures as low as -35°C; the Wellsville wetland operates at temperatures that can drop below -20°C. The multi-year performance history of these two wetland systems demonstrates that wetlands are a viable and cost-effective treatment alternative, even under cold climate conditions.
Three- Phase Unsteady-State Relative Permeability Measurements in Consolidated Cores Using Three Immisicible Liquids
Authors: Cao P. , Siddiqui S.
Published: October 2011

This paper discusses results from a series of two- and three-phase coreflooding experiments on consolidated cores using three immiscible fluids and using an unsteady-state relative permeability setup. The three-phase extension of the Buckley-Leverett theory proposed by Grader and O’Meara (1988) and verified by Siddiqui et al. (1996) was used for calculating three-phase relative permeabilities from the dynamic displacement data. From the results of three-phase displacement experiment, three-phase saturation trajectories are mapped and then compared against results of DDI (decreasing of water phase and oil or heavy phase and increasing of gas or light phase during a dynamic injection stage) runs found in the literature. The DID (decreasing of water phase, increasing of oil or heavy phase and decreasing of gas or light phase) runs presented in the current work are unique which map a wide range of the interior region of the ternary diagram. However, bypassing was observed during the IDD (Increasing of water phase and decreasing of oil or heavy phase and gas or light phase) runs, possibly due to fluids reaching the residual saturations before the dynamic water injection. In the petroleum industry, empirical models are often used to extrapolate three-phase relative permeabilities from two sets of two-phase relative permeability data. The experimental three-phase relative permeability data from the DDI and DID runs are compared with the model data, and it is found out that in some cases these models cannot adequately provide satisfactory matches with the experimental data.
A New Compact Triaxial Perforation Tunnel Stability Tester
Authors: Saito Yuya , Sato Hirotaka , Morita Nobuo
Published: October 2011

Thick wall cylinder testers (TWC testers) are commonly used for evaluating perforation stability. However, the results are ambiguous since the standard TWC testers use cylindrical cores where only uniform confining pressure can be applied, while the real in-situ stress is directional around perforations. A new triaxial perforation tunnel stability tester (TPS tester) is developed to simulate perforation stability under more realistic conditions. Normally, it requires a relatively large pressure cell and three independent pressure pumps to create a triaxial stress state in a cubic sample. However, the equipment developed in this paper is as simple and as small as the standard TWC testers with the following configurations:

Sample is a cubic rock with a 0.5 inch hole as the standard TWC test. The dimension of the cubic sample is 1.5 in. × 1.5 in. and the thickness is adjusted by core availability (normally varies from 0.75 in. to 1.5 in.). The stress ratio of the horizontal to vertical stresses in perpendicular to the hole axis can be varied between 0.33 to 1.0. The pressurization system requires only one pump by increasing the two confining stresses proportionally. A square jacket has a device to induce the directional loading. The pressure cell is as small as the standard TWC tester and the test procedure is also as simple as the standard TWC test.

Using the above device, various rock samples are tested varying the ratio of horizontal and vertical stresses. The results show that unlike the standard TWC tests, the perforation stability tests with the same in-situ stress ratio as the field one do not require corrections of directional in-situ stress effect. Note that depending on rock non-linearity, complex correction factors from hydrostatic confining stress to directional stress is required for the standard TWC tests since pre-mature failures are commonly observed for hydrostatic loading. The equipment is handy and portable so that it can be used in a small field laboratory.
Structural and Stratigraphic Control on the Trapping Machanism in Stacked Reservoirs of Kuwait
Authors: Azim Shaikh Abdul , Al-Otaibi Basel , Al-Qattan Sarah , Al-Saad Bader
Published: October 2011

Two giant faulted domal structures are separated by a narrow saddle on the northern extension of Burgan Arch in Kuwait. The structures hold oil at multiple levels in Zubair, Burgan, Mauddud and Tuba Formations with varying entrapment mechanisms. The Zubair Formation is a major oil reservoir in Eastern structure but water wet in the structurally higher Western structure while the Tuba Formation is oil bearing only in the West and wet in East.

Multiple phases of oil migration, filling, up-fault migration and spilling of the traps due to tilting and faulting have been postulated from an integrated study of geochemistry, trapping mechanism and structural history. The early charge of immature and bio degraded oils have been replaced by more mature lighter oil. Part of the spilling and redistribution of oil is due to the structural tilting initiated during the Zagros orogeny. Deeper relict oil, geometry of a heavy-oil wedge, presence of higher porosity in carbonates, residual oil rims below the original oil water contacts indicate structural tilt towards the north and west. Another interesting feature is the presence of high asphaltene oil in the form of a massive "mushroom" plug in the central part surrounded by lighter oil in and Burgan formation of western structure. The immovable oil and nearby lighter oil at same depths have similar biomarkers indicating a common source but different spill/charge histories. The lighter hydrocarbons have moved up through faults in the crestal area leaving behind the asphaltene rich heavy oil. In Eastern structure, the major part of Zubair is devoid of movable hydrocarbons in structural traps due to up-fault migration, lesser charge and inefficient seal of cavernous Shuaiba limestone. In contrast, giant structural oil traps in Western structure are to due to the smaller oil leakage along the less intense faults and more charging from the southwest. Additional support to the migration theory is that all the overlying traps are filled to spill point other than Zubair. Hydrocarbons are trapped in Burgan and Mauddud due to seals provided by carbonate cemented sands of Middle Burgan and marine shales of Wara.

Understanding the redistribution of oil in structural traps and the basinal oil charging have been pursued in discovery and delineation of the stratigraphic traps of Zubair and Ratawi Formations of the Eastern structure. These traps are much smaller compared to the giant structural traps.
Predicting Shale Reservoir Response to Stimulation in the Upper Devonian of West Virginia
Authors: Moos Daniel , Vassilellis G. , Cade R. , Franquet J. , Lacazette A. , Bourtembourg E. , Daniel G.
Published: October 2011

A comprehensive site study carried out in an Upper Devonian shale gas reservoir at a site in southern West Virginia provided data to test a geomechanical model for stimulation of the Huron formation. Using a model in which natural fractures provide the primary conduits for production and are the major target for stimulation, and in which stimulation triggers shear slip on those pre-existing fractures, we were able to predict the shape of the reservoir volume stimulated by injection of high-quality foam and to match injection flow rates and pressures using a dual porosity dual permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. The resulting calibrated model matched both the relative contribution of the individual stages measured by production logging and the early-life well production. This suggests that similar models may in the future provide earlier and better production predictions, guidance for completion and stimulation design, and recommendations to minimize production decline and maximize well value.
Drill Pipe Dynamic Measurements Provide Valuable Insight Into Drill String Dysfunctions
Authors: Raap Constantijn , Craig Andrew D. , Graham Ryan
Published: October 2011

Recently the oil and gas drilling industry has become increasingly interested in drilling dynamics and vibration as a cause of reduced drilling performance, downhole tool and drill string failures. Historically, vibration data has been captured by an MWD tool incorporated in the lower BHA. Whilst this provides valuable information on the dynamic behaviour of the lower BHA, this approach is not always sufficient for understanding the drill string dynamics of more complex applications. Two case wells are discussed within this paper in which high frequency vibration data was recorded at several strategic and innovative points within the drill string. The acquisition and analysis of this data provided new insights of the dynamic behaviour of drill strings in high angle wells.

A large international operator experienced both excessive and erratic surface torque during the first horizontal section of a large development project. The available surface drilling parameters and MWD vibration data were analysed, but the cause for the excessive surface torque could not be explained. To gain an understanding of the dynamic conditions across the drill string and to help identify the cause for the excessive torque, multiple Downhole Dynamics Recorders (DDRs) were included in the drill pipe, at positions up to 2500 metres from the drill bit, for two subsequent wells.

The DDR data revealed that during periods of excessive surface torque, severe levels of sustained lateral vibration were present in the drill pipe, but not in the lower BHA, where traditional vibration measurement tools are located. Two drill string failures occurred during the second well and the fracture profile suggested that they were the result of fatigue failure. The DDR tools located in close proximity to the failure points recorded periods of severe and sustained lateral vibration. It is likely that fatigue failure of the drill string was accelerated by the high and cyclic bending stresses generated during these periods of vibration.

In conclusion, dynamic dysfunctions can be present at any point in the drill string and these dysfunctions can have severe consequences within a short period of time. Furthermore, it is shown that novel and untraditional downhole measurements are required to understand, and mitigate, these dynamic dysfunctions.
Hydraulic Fracture-Height Growth: Real Data
Authors: Fisher Kevin , Warpinski Norm
Published: October 2011

Much public discourse has taken place regarding hydraulic-fracture growth in unconventional reservoirs and whether fractures could potentially grow up to the surface and create communication pathways for frac fluids or produced hydrocarbons to pollute groundwater supplies. Real fracture-growth data mapped during thousands of fracturing treatments in unconventional reservoirs are presented along with the reported aquifer depths in the vicinity of the fractured wells. These data are supplemented with an in-depth discussion of fracture-growth limiting mechanisms augmented by mineback tests and other studies performed to visually examine hydraulic fractures. These height-growth limiting mechanisms, which are supported by the mapping data, provide insight into why hydraulic fractures are longer laterally and more constrained vertically. This information can be used to improve models, optimize fracturing, and provide definitive data for regulators and interest groups.
Performance Advance in Section Milling Technology
Authors: Stowe Cal , Ponder Andrew
Published: October 2011

Tungsten carbide cutter technology is over 50 years old, yet much of its potential for milling steel downhole was only recently realized with enhancements to the cutter design and the material composition. Substantial performance improvement was achieved by carefully tailoring the cutter geometry and carbide chemistry to the downhole environment.

This new technology was used to meet a North Sea customer's call for improved section milling performance. The goal was to reduce the number of days to plug and abandon a well for platform slot recovery. The results were remarkable, with an average of five days saved per well, which represented approx. US$3 million in savings for the operator. This was accomplished by reducing the number of milling trips from three to one. Ten wells have been milled to date, with uniformly good results.

In section milling, the mill is run to the desired depth and cutting knives are extended to cut through the casing wall. After cutting through, the knives mill down to remove the unwanted casing. The mill was run in conjunction with a downhole monitoring tool to obtain real time data during the case studies. This data helped optimize operating parameters to minimize downhole vibration.

The new cutting insert has significant advantages over a conventional insert. The new carbide chemistry provides both impact and wear resistance, and the new geometry reduces rubbing area for faster cutting. The edge design is both sharp and impact resistant, and features an effective chip breaker to reduce cuttings packoff while milling.

Recent implementation of the new technology, its successful outcome, and lessons learned from its use in offshore plug and abandonment will be included for review and discussion.
Formalization and Standardization of the Smart Well Modeling Workflow
Authors: Hudson John D. , Alves Ibere , Khoshkbarchi Mohammad
Published: October 2011

Case studies and related to approximately 30 oil and gas production fields containing smart wells were reviewed to consider the work process that was used to justify the incremental investment in hardware and installation cost. These fields are from two operating companies and are distributed across most major oil and gas productive regions worldwide. The paper outlines key findings from the review, recommends a project-stage-based modelling workflow and presents opportunities for improvements to support more rigorous and efficient design decisions.
Challenges and Surprises of Abnormal Pore Pressures in Shale Gas Formations
Authors: Zhang Jincai , Wieseneck James
Published: October 2011

Drilling the gas-bearing shales in the Bossier and Haynesville formations in northwestern Louisiana presents many drilling challenges. Pore pressures increase from slightly elevated levels to a surprisingly high geopressures over short intervals. These pressures, if not correctly predicted, can lead to dangerous gas kicks and potentially blowouts. In the shale gas formations, conventional log-based pore pressure prediction techniques did not work well. The presence of gas in the shales adversely affected the compressional velocity. The impact of the Sabine uplift also reduced the ability of conventional pore pressure techniques to quantify pressures adequately in the objective formations. Instead we analyzed 54 kicks and other downhole measurements across the field to analyze the abnormal pressures. This approach yielded consistent results and provided a reliable basis for pore pressure prediction. The pore pressures in the lower Bossier and Haynesville shale gas formations show highly overpressured after a overpressure transition in upper Bossier shales, and unloading effect on pore pressure in those formation are also identified. Using the kick derived pore pressure model and improved log-based effective stress models, we developed a comprehensive pore pressure prediction method.
Drilling with a Balanced-Activity Invert Emulsion Fluid in Shale: Is It Sufficient for Maintaining or Enhancing Wellbore Stability?
Authors: Hemphill Terry
Published: October 2011

The great majority of wellbore stability problems encountered while drilling occur in shale formations. As invert emulsion drilling fluids (IEF) are commonly used to drill reactive shales in today's challenging wells, better understanding is needed of shale failure with exposure to IEF. Over the years, the concept of shale stability and interaction with IEF has been linked to several theories:

Semi-permeable membrane theory Osmotic pressure theory Balanced activity theory

Understanding of these individual theories is helpful to interpreting experimental data presented in this paper.

The shale that is the subject of this study was cored from deepwater operations, offshore West Africa. The operator who supplied the core had previously tested core samples in air, in water, and in a triaxial test apparatus. The results from the tests are reported here. Later, experimental testing of the deepwater shale was performed with a new test apparatus that has been presented to the industry. In short, this new appartus allows for shale samples to be directly tested under downhole conditions, and results have been shared with the drilling industry. Analysis of the test results in light of "balanced activity" theory calls this theory into question. The results show that even at an activity level higher than the known shale activity level, water was able to enter the shale and weaken it. This paper uses the concept of "chemomechanical balance" to explain measured results in terms of the coupling of shale mechanical properties and IEF chemical activity and the resulting consequences for selection of activity levels for IEF.