bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparing the Benefits: Use of Various Well Head Gas Coning Control Strategies to Optimize Production of a Thin Oil Rim
Authors: Nennie E. D. , Savenko S. V. , Alberts G. J. N. , Cargnelutti M. F. , van Donkelaar E. 
Published: October 2009

Abstract
With an increasing number of smart well applications being installed in the field, more knowledge is required to optimize their operation. This paper compares the benefits of various wellhead gas coning control strategies to optimize production of a thin oil rim. This study is performed within the "Integrated System Approach Petroleum Production (ISAPP)" knowledge center of TNO, TU Delft and Shell.
For this study a field case model is used, which has been validated with field data. The field case is a thin oil rim with a horizontal well. Due to the location of the horizontal well in the oil rim, the well is particularly susceptible to gas coning. Besides gas coning, wax precipitation is a second production constraint. This makes this well challenging to operate. Different production strategies are investigated and compared against each other: intermittent production and continuous production with pressure differential control.
The results of the different production strategies are presented by analyzing the advantages and disadvantages for the different gas coning control strategies, satisfying the given constraint of gas influx. This study reveals the difference in the cumulative production between the two strategies. The use of a closed loop control strategy can lead to a larger oil production in the same amount of time.
This paper shows the viability of using dynamic simulation models to quantitatively assess the benefits of various production optimization strategies. This allows operators to compare emerging smart well technologies, and increase trust in specific technologies that could be of an added value to their operation. Even though much has been published about the potential benefits of a smart field philosophy, few published field cases are available. This paper offers a field case testimony of the comparison of various feedback control strategies for purpose of production optimization.
Proppant Transport in Slick-Water Fracturing of Shale-Gas Formations
Authors: Dayan Adam , Stracener Shaun M. , Clark Peter E. 
Published: October 2009

Abstract
Since proppants were first used in hydraulic fracturing, the question of placement in the fracture has remained, for the most part, unanswered. Prediction of proppant transport is important in both treatment design and post-treatment analysis. The transport process has been studied since the late 1950s and a great deal has been learned from the simple laboratory models used in these studies. There are, however, a number of factors that have been overlooked in these studies that we believe are of primary importance. There are indications that fracturing in gas shale plays can produce complex fracture networks. Little is known about the propensity of the slurry to travel through the network. To examine this question, we have constructed a small one-dimentional fracture model with a bifurcation with each wing having equal length and cross-sectional area. We have also constructed a larger three-dimensional slot model to study the process more complex flow field. Results from the small model indicate that flow into the side slot does not occur below some threshold flow rate. This paper summarizes the work that has been done in the area of proppant transport in settling fluids and reports new data on the transport of proppant in multiple fractures.
A Field Demonstration of a New Chemical Stimulation Treatment for Fluid-Blocked Gas Wells
Authors: Butler Mark L. , Trueblood John B. , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R. , Johnson Doug 
Published: October 2009

Abstract
The loss of productivity due to liquid blockage in gas wells is a common problem. Dropout of condensate from gas and/or water accumulates in the pores of the rock near a producing well or within a hydraulic fracture, causing a significant reduction in gas relative permeability, curtailing production. As a solution to this problem, we have developed a chemical treatment designed to increase flow rates of blocked gas wells. The treatment alters the wettability of the solid surface, minimizing capillary pressure and increasing the relative permeabilities of gas and condensate. In laboratory core flood experiments, application of this chemical treatment increased flow rates by a factor of about 2 for two-phase flow of gas and condensate, gas and water, and gas and volatile oil. To bring this technology from the laboratory into the field, we stimulated a blocked gas well. The initial results of this field trial are reported in this paper and demonstrate the treatment was highly effective.
Haynesville Shale—One Operator's Approach to Well Completions in this Evolving Play
Authors: Pope Charles , Peters Billy , Benton Tim , Palisch Terry 
Published: October 2009

Abstract
The Haynesville-Bossier (HB) Shale is an extensive gas resource that has received significant publicity over the past two years, and is currently being developed by numerous operators. Since the HB is a relatively new play, it is anticipated that there will be many learnings in the future that will further improve well completions. However, the more quickly data-sharing and adoption of best practices occurs, the more effectively this tremendous resource will be developed.
This paper will describe some of the reservoir and completion concerns that have driven this operator's current completion philosophy, particularly as they affect well stimulation. Some of the topics described in the paper include: Consideration of vertical and horizontal wellboresHorizontal lateral placement within the vertical pay sectionOrientation of wellbores with respect to anticipated fracture azimuthFracture stage isolation considerationsPerforation strategyDesign and implementation of hydraulic fracture treatmentsConsiderations to accommodate elevated temperatures and stresses in the frac designManagement of closure stresses on proppant
Hydraulic fractures are the key to unlock the potential of most low permeability shale reservoirs such as the Haynesville Shale, and many drilling and completion decisions must be made to ensure successful placement of the stimulation treatment. Although the approach used on initial wells is expected to evolve with future experimentation and optimization, it is hoped that this early discussion of current design philosophy will be useful to the SPE audience, and allow the industry to optimize their Haynesville completions in a timelier manner.
Bidirectional Downhole Barrier Valve for Lubricator Applications
Authors: Andrews Thad , Sloan Jim 
Published: October 2009

Abstract
Bottomhole assemblies (BHAs) are becoming much longer to carry equipment to the bottom of the hole. In many instances, these BHAs can be many hundreds of feet in length and may need to be passed into a live well. Under traditional conditions, a top-side lubricator is used and mounted directly to the wellhead to contain well pressure as tools are run into the hole. However, with today's longer-length BHAs, it becomes impossible to provide a lubricator with enough length to place on top of the wellhead to run tools.
As a result of the more common use of extremely long BHAs, a solution is desired to provide a barrier valve that is resident in the tubing string that allows the section of tubing between it and the wellhead to act as the lubricator. This barrier valve must be bidirectional in sealing capability to hold pressure from both above and below the valve.
This paper discusses a new barrier valve that can be used as a lubricator valve and has a unique closure mechanism that allows it to seal pressures of 10,000 psi and potentially higher, from both above and below. It is operated hydraulically from the surface via dual control lines with one port used to manipulate the valve into the open position and the other port to manipulate it to the closed position. In this scenario, the valve control system is neutrally balanced and pressure only needs to be applied during shifting of the valve to the appropriate position. In addition, the valve control system is tubing-pressure-insensitive, which allows for extremely low shifting pressures that are typically well below tubing pressure.
This paper presents the design considerations for such a valve. Test results will demonstrate the capabilities of this new valve with respect to high-pressure sealability across the closure mechanism combined with extremely low operating pressures required for valve control.
Worldwide Deepwater Petroleum Exploration and Development Prospectivity: Comparative Analysis of Efforts and Outcomes
Authors: Iledare Omowumi O. 
Published: October 2009

Abstract
The global search for environmentally friendly energy resources is increasing. However, there is a general consensus that fossil fuel resources will remain a significant component of the global energy supply mix and the status of fossil fuels in the global energy economy does not appear ready to change in the near future. Increasing amounts of petroleum resources must therefore be found and developed to meet the global fossil fuel demand growth. Thus, the search for new fossil fuel resources must be extended to more remote areas than in years past. This paper describes qualitatively the primary factors underlying deepwater petroleum exploration and development prospectivity worldwide. The paper evaluates the attractiveness and prospectivity of worldwide deepwater offshore basins using empirical indicators to describe efforts and outcomes. The empirical indicators derived from deepwater specific data from private and public sources show that the expansion in worldwide Deepwater operations is a predictable response to the growth in global oil demand as the finite nature of petroleum resources onshore becomes more apparent to oil and gas operators worldwide. Further, the paper shows that the evolution of deepwater petroleum development is very pronounced around the three Atlantic Basin deepwater zones (Africa, Latin America, and North America--Gulf of Mexico) and that these regions have become an important element of the offshore oil and gas industry.
Avoiding Losses in Depleted and Weak Zones by Constantly Strengthening Wellbores
Authors: van Oort Eric , Friedheim Jim , Pierce Toby , Lee John 
Published: October 2009

Abstract
Drilling depleted or weak zones has always been a challenge, but with the aging of fields and the desire to drill to deeper in-field plays, the situation is becoming more exacerbated. The typical problems associated with drilling these types of intervals are lost circulation, stuck pipe and wellbore instability resulting in significant and expensive non-productive time (NPT) and costly remediation operations. Conventional lost circulation remedies (e.g., pumping lost circulation pills and squeezing) have given way to popular wellbore strengthening solutions. Our approach to strengthening, based on beneficial manipulation of fracture propagation pressure and continuous application of specialized wellbore strengthening additives has had tremendous success in reducing downhole mud losses by more than 80% in Gulf of Mexico deepwater operations and dropping the cost of these incidents out of the top 10 contributors to NPT.
This paper focuses on the various theories and approaches to wellbore strengthening and what the available field and literature data actuallysupport. Building upon this, the approach of gaining wellbore fortification through fracture propagation resistance (FPR) enhancement is introduced, for which experimental results, field data and case histories are shared. Central to our application of FPR to drill challenging deepwater production wells is the notion of providing continuous wellbore protection through a novel and unique solids recovery and reintroduction method that allows for drilling with high concentrations of wellbore strengthening materials (WSM) in the drilling fluid.
Effect of Pressure, Temperature, and Solution Gas on Oil Recovery From Surfactant Polymer Floods
Authors: Roshanfekr M. , Johns R. T. , Pope G. , Britton L. , Linnemeyer H. , Britton C. , Vyssotski A. 
Published: October 2009

Abstract
Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding is of great current interest owing to the need to recover oil left behind after primary and secondary recovery. If designed properly, these enhanced oil recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by doing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature and the importance of those experimental results are conflicting.
This paper investigates the effect of pressure, temperature, and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor type II+) to lower microemulsion (Winsor type II−), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. We derive a new thermodynamic model to explain why the logarithm of oil and water solubilization ratios is linear with pressure or inverse temperature. We also use a numerical simulator to show how to design the chemical processes to account for phase behavior shifts with pressure and solution gas to achieve good oil recovery.
Data Assimilation Using the Constrained Ensemble Kalman Filter
Authors: Phale Hemant A. , Oliver Dean S. 
Published: October 2009

Abstract
When the ensemble Kalman filter (EnKF) is used for history matching, the resulting updates to reservoir properties sometimes exceed physical plausible bounds, especially when the problem is highly nonlinear. Problems of this type are often encountered during history matching compositional models using EnKF. In this paper, we illustrate the problem using an example in which the updated molar density of CO2 in some regions is observed to take negative values while molar densities of the remaining components are increased. Standard truncation schemes avoid negative values of molar densities, but do not address the problem of increased molar densities of other components. The results can include a spurious increase in reservoir pressure with a subsequent inability to maintain injection. In this paper, we present a method for constrained EnKF which takes into account the physical constraints on the plausible values of state variables during the data assimilation. The proposed method can be implemented in two different approaches, both of which convert inequality constraints to a small number of equality constraints. The first approach uses Lagrange multipliers to apply the active constraints. In the second approach, the constraints are used as virtual observations for calibrating the model parameters within plausible ranges.
The constrained EnKF method is tested on a 2D compositional model and on a highly heterogeneous 3-phase flow reservoir model. The effect of the constraints on mass conservation are illustrated using a 1D Buckley-Leverett flow example. Results show that the constrained EnKF is able to enforce the nonnegativity constraints on molar densities and bound constraints on saturations (all phase saturations must be between 0 and 1), and achieve a better estimation of reservoir properties than is obtained using only truncation with EnKF.
Effects of Fluids, Frequency and Heterogeneity on Elastic Properties of Carbonate Rocks
Authors: Sharma R. , Adam L. , Prasad M. 
Published: October 2009

Abstract
Understanding factors controlling the elastic behavior of saturated rocks is critical for characterizing carbonate reservoirs. These elastic properties are often mapped using seismic data. Elastic properties, often derived from inversion of seismic data via velocities, form important inputs for reservoir engineering calculations and simulation studies. Normally, in absence of site-specific measurements at reservoir temperature and pressure, empirical models or data from analog formations are used. However, elastic properties of rocks are controlled by variation in saturant type and its dependencies on pressure and temperature, in addition to rock heterogeneity. The characterization of heterogeneities is important for obtaining rock physical parameters and for understanding flow mechanics in carbonate reservoirs using upscaled geological model for reservoir simulation. Broad objective of this study are, 1) Measure the elastic moduli of rocks as they change with saturant and amount of saturations. 2) Calibrate these changes in rock strength, to understand the difference between the static and the dynamic elastic moduli. 3) Investigate effects of frequency-dependence of elastic moduli and effects of its variation on reservoir engineering calculations and simulation studies. Present paper discusses the effects of fluids, frequency and heterogeneity on the elastic properties of carbonate rocks. Their effects on reservoir engineering calculations will be discussed in future communications.
In this study, comparisons are drawn between a set of homogeneous and heterogeneous samples for their varied response to varying saturant, amount of saturation (Sw), frequencies and differential pressures. At ultrasonic frequencies, bulk modulus in the heterogeneous sample varies by 22% from dry to partial (water saturation, Sw = 56%) saturation stage, and by an additional 7% from partial to full saturation, whereas in the homogeneous sample, bulk modulus varies by 27% from dry to partial saturation (Sw = 90%) and by 29% from partial to full saturation. Similarly, the shear modulus in both samples varies by −2% and −12%, respectively from dry to partial saturation, and by 3% and 10%, respectively from partial to full saturation. For another set of homogeneous and heterogeneous samples we measured the bulk and shear modulus as a function of frequency, saturant and differential pressure. We observe that most samples show an increase in bulk and shear modulus with frequency. We also observe weakening and strengthening of the shear modulus from dry or with a light hydrocarbon to fully-brine saturated pore spaces. Investigations were also carried out for finding any possible correlation between the measured permeability and measured velocity in carbonate rocks. We found no definite correlation between permeability and velocity for both homogeneous and heterogeneous samples.
Challenges on Drilling and Completion Operations of Deep Wells in Ultra-Deepwater Zones in the Gulf of Mexico
Authors: Cunha J. C. , Moreira O. , Azevedo G. H. , Pereira B. C. M. , Rocha L. A. S. 
Published: October 2009

Abstract
Currently some of the most challenging wells being drilled by our industry are located in deepwater zones in the GOM. Many of those wells are in water depths of 8,000 ft. or more and several are targeting reservoirs around 30,000 ft. and beyond.
Drilling engineers face many challenges when planning drilling and completion operations for such wells. There are not many rigs available to drill in ultra-deepwater, and even the modern rigs capable of operating in this environment will present limitations ranging from the maximum mud weight possible to be used, due to riser restrictions, to the hook load capability to run very heavy intermediate casings that will easily surpass one million pounds.
The well itself will present many problems including high pressure and high temperature formations, the need of multiple casing strings, unstable formations, hole cleaning, unexpected presence of tar zones, huge layers of salt, the need to underream the well, difficult to do an efficient evaluation program etc.
On the completion side, the challenges can be even more demanding, with the need to complete multiple zones while trying to minimize future expensive workover operations.
This paper presents some practical experiences on dealing with various of the abovementioned problems and also suggestions to make the problems manageable. It might be emphasized that we do not have a perfect solution to all problems and that we are far to have the most efficient solution to drill deep wells located in ultra-deepwater zones in the GOM. However, with daily operational costs reaching one million dollars or more, it is our intention in this paper to discuss the problems, to point out some possible directions, to show some field cases and to open a discussion that might benefit the entire industry.
Assessing the Impact of Microseismic Location Uncertainties On Interpreted Fracture Geometries
Authors: Maxwell Shawn 
Published: October 2009

Abstract
Interpretation of fracture geometry is an important aspect of microseismic monitoring, especially for hydraulic fracture stimulations. The fracture geometry is often inferred directly from the microseismic locations, particularly by using the few events comprising the edges of the cloud of microseismic locations. These few events are frequently used to measure the fracture dimensions of height and length, as well as the width to interpret fracture complexity. In this paper, a synthetic dataset assuming different location uncertainties is constructed, to illustrate how location errors relate to uncertainties in the fracture dimensions. If the edges or extremities of the microseismic clouds are used to interpret the fracture extents, the synthetic data demonstrate that these locations are potentially statistical outliers of the microseismic uncertainties. Therefore, the extremities are shown to be biased towards measuring larger fracture dimensions, and potentially misinterpretation of fracture complexity associated with mislocated events. A technique termed compression is introduced which considers the probability density function to interpret the statistical spatial scatter of the microseisms, to enable an interpretation of the fracture dimensions ‘compressed’ away from the extremities of the cloud. The synthetic data is used to validate the technique, demonstrating that the resulting fracture geometries are more accurate and are less biased by the location uncertainty. The compression technique was applied to a hydraulic fracture image, for a dataset which was processed using automatic data processing and then reprocessed with a more accurate algorithm. For both the automatically processed and the refined locations, the compression technique results are similar, confirming the technique is relatively insensitive to the location errors. The refined image was sufficiently accurate to identify two discrete structures in the image.