bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.