bluuebunny/crossref_metadata_2025_split huggingface dataset:
Upscaling of Miscible Floods: An Extension to Koval's Theory
Authors: Jain Lokendra , Lake Larry W 
Published: September 2013

Abstract
Modeling of viscous instabilities and channeling requires models at centimeter or millimeter scale establishes a need for an upscaling scheme that could predict production with as few parameters possible. We develop such an analytical model of volumetric sweep that aims to decouple heterogeneity from the mobility ratios for tertiary miscible displacements. The developed analytical model is solved by applying method of characteristics. The application is to provide quick estimates of oil recovery of displacements, as well as to provide scale up information for larger simulations. The original Koval work also provides a means of estimating oil recovery for miscible floods but it works if a single front displacement is assumed. This could be a limitation for tertiary floods where an oil bank forms and displacement has two fronts (Figure 1). This work also accounts for the interactions between these two fronts as they move in the reservoir, unlike previous work (Mollaei, 2011). This work could further be extended to tertiary polymer and ASP floods where similar oil bank forms at pixel scale for prediction of oil recovery.
For fields with large heterogeneity, which have severe channeling, the oil cut is small, the production history takes a long time to complete, and ultimate recovery is reached very slowly. Two-front, gravity-free, displacements can be modeled using the new model based on Koval's theory. This model captures the aspects such as oil cut reaching a peak and then falling off with very high ultimate recovery times for tertiary miscible floods.
Current techniques for upscaling displacement rely on empirical models. The parameters on which these empirical methods depend cannot be easily correlated to the parameters (heterogeneity, mobility ratio and dispersivity) that govern flow at the fine scale. This technique provides a way to predict performance without the use of computationally expensive fine scale simulation models.
Imaging of Fluid Mobility in Fractured Cores Using Time-lapse Positron Emission Tomography
Authors: Maucec Marko , Dusterhoft Ron , Rickman Richard , Gibson Ron , Buffler Andy , Stankiewicz Maciek , Heerden Michael van 
Published: September 2013

Abstract
Positron emission tomography (PET) continues to have wide-ranging medical application and is based on the detection of gamma radiation emitted from the decay of certain types of radionuclides. Modern PET scanners produce three-dimensional (3D) images of the radiation source, in discrete time steps, using tomography analysis. This paper presents an application of PET for studying fluid mobility in pressurized low-permeability rock samples in the presence of natural fractures. This technique uses a high-resolution PET scanner and image reconstruction based on filtered back-projection. Traditional techniques have been limited to pressure measurement of fracture conductivity and effective permeability, but little is understood about the dynamic flow and velocity profiles within the fracture.
The objective of this work was to investigate if it is possible to measure the time-lapse distribution of the fluid flow as a function of the overburden stress. PET imaging was applied to the flow of brine solution, which was tagged with 18F-fluorodeoxyglucose (FDG) positron emitting radionuclide, through nonfractured sandstone and naturally fractured shale cores. A special composite container was manufactured to sustain high-pressure conditions and minimize the absorption of emitted gamma rays. The experimental apparatus is described, and it is demonstrated that the 3D images obtained with a grid resolution of 2 × 2 × 2 mm3 allow clear determination of the fluid flow rate through the core as a function of overburden pressure and time. PET images are direct observations of the radiation source and allow an unambiguous determination of the fluid distribution in the core. The results of this research can be used to validate the numerical modeling of fluid flow through fractured rock matrices, to enable more accurate estimates on the directionality of fractures from the fluid distribution as a function of time, and to obtain more quantitatively sound estimates of fracture connectivity.
Putting a Value on Estimated NGL Volumes in Prospect Evaluation
Authors: Harrison Bob 
Published: September 2013

Abstract
Natural gas liquids (NGLs) are recovered from the produced wet gas stream by a more complicated process than typical separation that involves additional chilling and compression. Thus, NGL volumes can be obtained by decreasing a field's wet gas production profile, but this should be avoided unless a premium price can be obtained for the liquids relative to the gas that is used to make them.
Traditionally, in the evaluation of undrilled exploration prospects in the North Sea, there is so much uncertainty in the forecasts of product prices that analysts tend to only consider oil, condensate and sales gas, when deriving an economic value for a prospect. However, some North Sea Operators routinely offer farm-in opportunities where the probable resource estimates in their prospects, which are assumed to contain volatile oil, are broken down into oil, dry sales gas and NGLs. This practice has come about as the price differential between oil and gas has grown. The upshot is the company farming in will see a higher prospect valuation, and thus receive a lower working interest for the same money it puts on the table.
Some say that putting a value on NGLs in prospect evaluation is over-sciencing the process. They argue that as analysts are guessing the hydrocarbon type and its gas in solution, it is going a step too far to claim they can estimate NGL yield too with any confidence. They also hold the view that the range calculated for a prospect's resources should be wide enough to adequately accommodate any additional benefit which may result from NGLs, as they would be taken care of in the noise.
Those that support attributing value to NGLs counter that the real issue is a matter of the amount and reliability of the technical data on the opportunity. They argue that if analysts can determine the NGL yield with an acceptable level of accuracy, then it should be considered, provided that one remembers to include the incremental facilities cost of NGL recovery. Both points of view are discussed, in particular whether companies may have under-valued and walked away from past opportunities by failing to put a value on NGLs. By valuing prospects higher, companies can live with a higher exploration risk and tolerate higher drilling costs. The paper briefly considers the ethics of a company adopting a binary strategy of assigning value to NGLs when farming out, but ignoring it when farming in. Finally, appendices provide detailed descriptions of how to use a linear version of the expected value concept for farming analysis and give a simple workflow to estimate potential NGL recoverable volumes for a North Sea volatile oil prospect. Many of the issues discussed also apply to gas condensate exploration targets, but this paper focuses on those prospects that are thought to contain volatile oil.
Readers can draw their own conclusions as to which view is better, yet the majority of the feedback from analysts was that many prefer not to assign a separate value to the potential NGL stream from a volatile oil prospect in the North Sea.
Assessment of Unlocking Production from the Ursa and Princess Fields Using Integrated Production Modeling
Authors: Gorur Keshav , Harris Rob , Meyers John 
Published: September 2013

Abstract
The Ursa and Princess oil fields lie in the Mississippi Canyon (block 810) of the Gulf of Mexico about 130 miles south east of New Orleans. Both fields produce to a common host, the Ursa Tension Leg Platform, moored in approximately 3,800 ft of water. Ursa production wells were completed with dry tree direct vertical access (DVA) while Princess utilizes wet tree subsea wells tied back about four miles to the host through dual insulated flowlines and risers, as shown in Figure 1. Production at Ursa began in 1999 and Princess in 2004 with both fields producing from the main Lower Yellow (LY) and secondary Sub Yellow (SY) reservoirs. Currently, seven wells are producing from the LY and two from the SY. A waterflood of the LY, comprising four subsea injectors (two in Ursa and two in Princess), was initiated in 2008 in order to replace voidage and improve sweep efficiency and hydrocarbon recovery.
Recent successful production wells in Princess coupled with the waterflood response have created a bottleneck at the subsea flowlines. At current operating conditions, this restriction means that future projects would be have to be deferred as they cannot fully deliver gains due to the back out of existing production. In addition, an earlier screening study had identified Princess as a strong candidate for subsea boosting in order to increase production from existing wells. The asset team therefore initiated a de-bottlenecking and subsea boosting assessment that was carried out by a multidisciplinary team.
A subsurface team formed a part of the greater multidisciplinary team. One of the tasks of the subsurface team was to deliver production functions for each of the screened re-development concepts. Production was one of the key inputs in evaluating economics which in turn was a primary driver of the concept selection decision. While the re-development concepts were specifically for the Princess field, the expectation was that changes there would influence hydrocarbon recovery from Ursa as the two fields are in pressure communication within the main LY reservoir and both benefit from waterflood support. This study also needed to include future Princess subsea wells targeting additional accumulations not in communication with the LY or SY as part of the re-development. These reservoirs are expected to have a range of different initial pressures and contain hydrocarbons of varying properties.
Hence, it became clear at the start that there were several dependent and independent moving components and constraints that had to be considered together to get an accurate assessment of the systemic effects that would influence total production. The team therefore decided to build an integrated production model, containing the entire production system from reservoirs to topsides, to obtain production functions for the screened concepts.
The Impact of Shale Preservation on the Petrophysical Properties of Organic-Rich Shales
Authors: Jung Chang Min , Zhou Junhao , Chenevert Martin , Sharma Mukul 
Published: September 2013

Abstract
The procedure to evaluate the basic petrophysical properties of hydrocarbon bearing shales varies substantially in the oil and gas industry, making it difficult to compare experimental results across labs. In this paper, we present a methodology that we hope will become an industry standard for preserving and preparing shales for petrophysical measurements.
We present the following series of measurements and their results to demonstrate the petrophysical properties of both well preserved and poorly preserved hydrocarbon bearing shales: native shale water activity, original fluid content, density, mineralogy, sea water and nitrogen permeability, swelling, Brinell hardness, and P-wave and S-wave velocities.
An adsorption isotherm test was used to measure the native shale water activity. We used the GRI method to measure the original fluid content and density. Mineralogy was determined with X-ray diffraction. A pressure transient technique was employed to measure the permeability of fluid and gas passing through a shale sample. We also compared our permeability data with the experimental data using the conventional GRI method. Brinell hardness was measured before and after swelling with a multi-scale durometer. Using a pulse transmission set-up, we also measured wave velocities before and after swelling. Young's modulus and Poisson's ratio were calculated with wave velocity data.
The large differences in shale properties between preserved and un-preserved samples as reported herein, clearly indicate that shales should be preserved at the well site and tested with a standard procedure ensuring minimum alteration of fluids from the shale. Failure to follow a standard procedure leads to measurements that do not reflect the "true" or in-situ properties of the shale. Instead, the measurements can be a factor of 2 or 3 different from the "true" value. The shale handling, preservation and measurement techniques and procedures presented in this paper can be used as a standard protocol for studying organic rich shales.
Case History—Combining Extreme Overbalance and Dynamic Underbalance Perforating Techniques in Ecuador
Authors: Poveda Patricia , Izurieta Alvaro , Lozada Julio , Rios Federico , Scott Martin Schoener 
Published: September 2013

Abstract
The effective combination of propellants to generate a high-pressure pulse to create micro fractures has been proven to be successful in a number of wells in Ecuador.
Recently, the inclusion of surge chambers in the bottom hole assembly has been proven to provide improved cleanup of the perforation tunnels created by jet perforators. This minimum surge pressure across the formation results in a dynamic underbalance that improves well productivity. Owing to the improved cleanup, there is a better path between the reservoir and the wellbore, which has demonstrated a more than 50% increase in well productivity. The ability to delay the opening of the chambers after gun detonation is critical in creating a dynamic surge from reservoir to wellbore, thus enhancing the dynamic flow and removal of fluids and solids from the perforation tunnels.
This combination of overbalance and dynamic-underbalance immediately after perforating has also provided a method for cleaning perforation tunnels, even when perforating overbalanced with wireline-conveyed guns.
This technique has been highly successful in the East Basin of Ecuador, especially now that near-wellbore stimulation techniques to clean the perforation tunnels can be achieved with wireline-conveyed guns instead of using a rig to provide tubing-conveyed perforating (TCP) services to create optimum conditions during perforating.
This combination of techniques provides an effective solution at a reasonable cost that optimizes reservoir connectivity with the wellbore, significantly increasing the productivity index.
However, for these techniques to be used successfully and create the necessary conditions to remove debris damage from the perforation tunnels, it is imperative that the software models and simulations be provided by experienced and well-trained engineers.
Prior to the job, the service is modeled using state-of-the-art software simulators to predict the dynamic forces acting on the wellbore. When the job is executed, fast-gauge memory recorders are used to capture the pressure and temperature data at the time of the perforation event to validate the modeling. This technology has demonstrated great success in Ecuador by improving well productivity by as much as 50% when compared to other nearby wells in the field.
Determining Hydraulic-Fracture Orientation and Height Using After-Fracture Borehole Acoustic Attributes in the Vaca Muerta Unconventional Reservoirs
Authors: Velez Edgar , Ponce Jorge , Tessari Sergio 
Published: September 2013

Abstract
As high-permeability reservoirs approach their last years of productivity, oil and gas production will likely come from low-permeability formations, requiring hydraulic-fracture stimulation to be economically promising. This is the case in Argentina with the recent development of unconventional reservoirs targeting the Vaca Muerta shale play.
The success of a hydraulic-fracture job depends on several factors, including the formation geology itself, the formation mechanical properties, field-stress regime (direction and magnitude), minimum horizontal stress contrast, and the transition from the simulation to the execution of the fracture job. Production companies need tools that help them determine how successfully the hydraulic fractures have optimized well production and field development. These tools should provide information about hydraulic-fracture conductivity, geometry, complexity, and orientation.
This paper presents the application of time-lapse anisotropy analysis, using data from an acoustic scanning platform combined with a gyro, to obtain information such as the propped fracture height and the hydraulic-fracture orientation. This information is essential in planning horizontal wells when the well axis is to be transverse to the direction of the fractures. Application of the acoustic scanning platform technology as a fracture optimization tool in the Vaca Muerta shale play allows for a comprehensive evaluation of the hydraulic-fracture geometry, which can be combined with post-stimulation production results to provide direct impact in the well production and field development.
Fifteen Years of Expandable Sand Screen Performance and Reliability
Authors: Ismail I Mohd , Geddes M W 
Published: September 2013

Abstract
Expandable Sand Screen (ESS®) was first field trialed in 1997 with the idea that eliminating the annulus between the sand screen and wellbore would improve downhole sand control, while allowing enhanced reservoir performance and management. By the end of 2012 ESS was installed in 677 wells, with over 418,184ft of screen deployed globally. As such, ESS has matured as a viable sand control technology combining Openhole Gravel Pack (OHGP) functionality with the installation simplicity of a Stand-Alone Screen (SAS) completion.
With performance, reliability and long-term well life expectancy of paramount importance to field development economics, an extensive installation database has been maintained. Over the past 15 years, observation and analysis of design, planning, field implementation and useful life cycle has been documented in this database. This performance insight provides the foundation for future reliability and has been used to identify learning opportunities, influencing the product evolution and technology application envelope.
With performance and reliability analysis provided and discussed in detail the applicable ESS envelope is outlined. Product design enhancement, methodical application evaluation and rigorous operating procedures result in improved successful use. Analysis of both infant and production failure trends are presented and show improvement. This data is used to estimate future life predictions using recognized reliability analysis tools. The applicability of ESS in openhole wells is highlighted, with continuing performance in oil producers, gas producers, water injectors and underground gas storage applications. There are various sand control technologies successfully utilized in reservoirs around the globe. This study outlines the applicable envelope for ESS use, providing insight to enable informed evaluation, life-of-well risk appraisal and ultimately reliable sand control completion selection for existing or new field development appraisal.
Proposed Alternative Method for Calculating Emissions from Hydraulic Fracturing Operations
Authors: Sexton Andrew , Hinman Lee , McKaskle Ray , Fisher Kevin 
Published: September 2013

Abstract
The United States Environmental Protection Agency (EPA) developed the Mandatory Greenhouse Gas Reporting Rule, published in the Code of Federal Regulations at 40 CFR 98, as a tool to help policy makers assess potential actions to take regarding greenhouse gases (GHGs). Subpart W "Petroleum and Natural Gas Systems" of 40 CFR 98 prescribes GHG emission estimation methodologies and reporting requirements for the oil and gas industry. One area where significant issues remain to be resolved is the estimation of GHG emissions from the act of flowing back gas wells following recent hydraulic fracturing operations.
As an alternative to measuring the flowback volume of GHG emissions from a fractured well, EPA presented equations for sonic and subsonic flow which appear to be derived from the ideal gas law. Anecdotal evidence from member companies of multiple trade organizations indicated that these equations may overestimate flow rates by as much as 600%.
Noble Energy Inc., with the help of Trimeric Corporation, investigated and evaluated empirical methods to estimate GHG emissions from flowback operations that follow hydraulic fracturing. A number of earlier developed correlations for multiphase flow were considered before choosing the Gilbert-type correlation as a potentially applicable equation for this case. The goal of this analysis was to compare the accuracy of the ideal gas type equation in a multiphase flow regime with a Gilbert-type predictive multiphase flow correlation using site-specific and field-regressed coefficients.
Measured data for daily and total cumulative gas, water, and oil produced, choke size, and tubing pressure for several wells within a field are needed to develop field-regressed coefficients for the Gilbert-type equation. However, once they have been determined, one singular daily average value of choke size, tubing pressure, and rate of produced liquid (oil and water) are all that is required to predict the total volume of produced gas emissions for other flowback operations in the field.
The results of this study indicate that the Gilbert-type correlation using field-regressed coefficients predicts the overall volume of gas produced during a flowback operation more accurately than the ideal-gas type EPA equation W-11B in 40 CFR 98.
Breakdown Pressure Determination - A Fracture Mechanics Approach
Authors: Jin Xiaochun , Shah Subhash N. , Roegiers Jean-Claude , Hou Bing 
Published: September 2013

Abstract
Accurate determination of breakdown pressure in the presence of pre-existing fracture (e.g., natural fractures or perforations) can assist engineers better manage expected fracture gradients. The classical models by Hubbert and Willis, and Haimson and Fairhurst did not account for the existence of pre-existing fractures in predicting breakdown pressure. In addition, the available fracture models for the calculation of breakdown pressure do not consider nonlinear internal pressure distribution in the pre-existing fracture. Finally, some of them either ignored near wellbore stress concentrations, or they are limited to specific fracture dimensions.
To overcome the limitations of current methodologies, a weight function method is applied to predict breakdown pressure of two general symmetrical radial fractures emanating from a borehole. A weight function parameter table and three weight function parameter correlations are provided for continuous dimensionless crack lengths from 0.001 to 100. For uniform pressure distribution in the pre-existing fracture, the weight function based breakdown pressure is compared against the PSA method [Paris and Sih, 1965; Abou-Sayed et al., 1978], the results show a good agreement. Weight functions are applied to predict breakdown pressure for uniform and nonuniform pressure distribution in a pre-existing fracture, and the results prove that the pressure distribution affects the breakdown pressure. Sensitivity studies are conducted to investigate the influence of pre-existing crack length, orientation, in-situ stress contrast, and fracture toughness on breakdown pressure. It indicates that breakdown pressure (1) does not always increase with increasing dimensionless crack length at different stress contrast, and (2) increase with increasing absolute value of deviation angle and fracture toughness. The weight function based breakdown pressure is further verified against measured breakdown pressure from laboratory hydraulic fracturing experiments by fine-tuning fracture toughness. The results are also in good agreement for selected successful fracturing experiments.