bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Inflow Control Device Technology and its Value Realization for Kuwait Oil Fields through Best Practices and Multidisciplinary Team Work
Authors: Al-Jasmi Ahmad K. , Siddiqui Mohammed A. , Al-Anezi Khalaf G. , Zaki Hasan
Published: September 2013

In the pursuit of maximizing oil production to meet the 2030 strategy of producing 4.5 MM bopd, KOC has adopted a massive plan of implementing new technologies through pilot trials. Some of the technologies successfully tested are fiber optic sensors for real time reservoir monitoring, horizontal wells for increased production through increased reservoir contact, inflow control device and interval control valves for improving cumulative production and managing reservoir uncertainties, multilateral wells to reduce well footprint with increased production and acid tunneling technology to gain oil from old wells in depleted reservoirs.

Horizontal wells are considered superior over conventional wells in terms of production improvement due to increased reservoir contact. Despite this, these wells pose severe production challenges due to variations in permeability, reservoir pressure, reservoir fluid properties and frictional pressure drop along horizontal section. Preventing water/gas breakthrough, equalizing inflow with minimizing pressure loss, minimizing annular flow and heel-to-toe effect, delay non-uniform water progress, avoiding by-passed oil, increasing sweep efficiency and ultimate recovery are some of the primary challenges that are required to be addressed for gaining optimum advantages of horizontal wells. One of the promising technologies to address all these challenges is the application of advanced completions, such as inflow control device (ICD) and interval control vale (ICV). These completions help to enhance hydrocarbon recovery and reserves management.

The technology was test trialed successfully through multidisciplinary team approach and best practices. The value addition of the technology was evaluated by interacting with major operators and service companies. The evaluation of ICD and ICV was done by inviting designs from all the major companies and appropriate systems were selected with respect to reservoir and fluid properties, maintaining the policies of commercial group. For the first pilot test, suitable wells and systems were selected to avoid drawbacks that might lead to pilot failure and eventually disapproval of the technology from top management. This paper describes the results of the first ICD and ICV pilots, methodology, best practices and selection criteria that ultimately resulted into large scale field implementation of these technologies.
Evaluation of Multi-Objective Methods for Portfolio Tradeoff Analysis
Authors: Kostuik K. , Valdez A. A. , Bordovsky J. , Mu Y. , Faig C.
Published: September 2013

Recent advances in multi-objective optimization technology enable improved solution quality, scalability, and flexibility for portfolio analysis.

A multi-objective evolutionary algorithm (MOEA) with innovative constraint handling was used for portfolio planning of offshore exploration & production projects. The MOEA method was used for tradeoff analysis and portfolio optimization. In order to facilitate direct comparison with alternative methods, a multi-objective evaluation framework was developed, and a simplified test problem was derived from historical planning data. The MOEA method was compared to three other portfolio planning methods: rank & cut, sample & filter, and mixed integer linear programming (MILP).

The study highlighted that the evaluation of multi-objective methods is itself a multi-objective problem. Methods that performed well on some criteria performed poorly on others, and no method dominated on all criteria. The presence of planning constraints proved critical, with unconstrained problems being easy to solve with traditional rank & cut, and constrained problems requiring some type of optimization method.

The MOEA method demonstrated several advantages. Even though the test problem was designed specifically to be a good match for the MILP method, the MOEA method was competitive on all criteria and excelled on solution spread, flexibility, and scalability. Published MOEA methods have the potential to enable new types of portfolio tradeoff analysis, although successful applications will likely require enhancements to published constraint handling techniques.

Multi-objective methods are in the early phases of petroleum industry adoption, so there is little knowledge of appropriate solution method evaluation criteria. The study highlights important and commonly overlooked issues in evaluating multi-objective methods.
‘LOSC’ Simulation: A Key to Introduce Heterogeneities in Turbidite Channel Complexes (Offshore Congo)
Authors: Gaillot J. , Labourdette R. , Bez M. , Bui T.
Published: September 2013

Hydrocarbon-bearing turbidite reservoirs are complex features, and their description needs to take into account heterogeneities at seismic and sub-seismic scales. The morphology and internal distribution of elementary channels are dependent on depositional setting, which controls the distribution of the main heterogeneities. The internal architecture of a channel complex is composed of multiple individual (elementary) channel stacks formed during repeated erosion/deposition cycles. A turbidite channel is not a simple funnel transporting sand to deep-sea areas but also may preserve slumps, collapse breccias and internal levees on its borders, resulting in the formation of internal heterogeneities (below seismic resolution). The sideways and down-dip movements of elementary channels in turbidite complexes show two typical patterns: lateral migration and vertical stacking. The spatial distribution of heterogeneities at the elementary channel margin is therefore constrained by the different channel patterns. Seismic data only display the outside geometry of channel lateral stack, i.e. a turbidite fairway.

Complexes of Laterally Offset Stacked Turbidite Channels (LOSCs) require a description based on the scale of individual channel bodies. The most common representation of channels in a fairway is by stochastic object modeling; i.e. populating the observed fairway with realistic forms representing individual channels, but with no established consistency between the individual channels. Furthermore, one essential characteristic of LOSCs is that they evolve by progressive migration laterally and/or down-dip. Stochastic object modeling provides an inadequate representation of this progressive evolution, and consequently a poor rendering of the heterogeneity distribution in the reservoir.

The methodology we propose consists of defining a realistic succession of individual channels that can accurately build the fairway observed on seismic. ‘Realism’ is defined using criteria from the shape of individual channels, and based on the amount of displacement necessary between successive episodes based on seismic interpretation.

This workflow, based on geometrical modeling, is illustrated using distinct Oligo-Miocene reservoirs from offshore Congo. The final result is a deterministic succession of channels laterally stacked to reproduce the envelope and lateral migration observed on seismic. Associated heterogeneities are integrated into the reservoir models using transmissibility multipliers, calibrated to match DST results and then applied to the entire models. The resulting architecture respects the natural architecture of the complex and provides a better simulation of flow pathways than that achieved by random object modeling. In the context of a pre-development initial reservoir model, the main interest of this method is to provide much more realistic long-term recovery factors for such complex reservoirs.
Maximizing Oil Production and Increasing ESP Run Life in a Brownfield Using Real-Time ESP Monitoring and Optimization Software: Rockies Field Case Study
Authors: Ratcliff Dustin E. , Gomez Cesar , Cetkovic Ivan , Madogwe Odafe
Published: September 2013

Marathon Oil operates several brownfields in the Rockies, most of which are approaching a producing life of 100 years. Most of the fields are on waterflood, with 86% of the oil production coming from the artificial lift method of electrical submersible pumps (ESPs). This ESP lift method has helped maximize the production of recoverable oil in these fields, achieving higher drawdowns and larger fluid volume handling.

Prior to 2010, Marathon's 770 ESPs were operated with out downhole gauges or sensors and no ESP real time systems were in use. This made it difficult to properly monitor the well and the equipment, leading to improperly sized ESPs, limited artificial lift optimization and lost oil production. In 2010 Marathon began installing downhole sensors in all ESP wells that were pulled for either a failure or a workover and download the data into an ESP real-time monitoring, diagnosis and analysis software system.

At the time of this paper, Marathon has installed downhole sensors in 430 of the 770 ESP wells. All ESP wells are presently being monitored via the ESP real-time monitoring and analysis software. During this short period of real-time monitoring, Marathon has realized production gains of more than 700 barrels of oil per day (BOPD) in one of the fields.

This paper compares previous operations to the results and data from the installation and connection of downhole sensors to the real-time ESP monitoring program. Monitoring methodologies, analysis and proper ESP optimization are detailed in several case studies.
Drilling Rig Sensor Data Validation in the Presence of Real-Time Process Variations
Authors: Ambrus Adrian , Ashok Pradeepkumar , van Oort Eric
Published: September 2013

The safe and efficient construction of a well requires close attention to how the well and the rig equipment behave as the well is drilled. This primarily involves monitoring and correctly interpreting all the data collected at the rig site. In the past, this was primarily accomplished with an experienced drilling crew. While we still continue to use mostly antiquated rig sensors that were introduced decades ago, there has also been an "explosion" in the number of new advanced sensors used on a rig. The argument put forward for the additional sensors is that they increase safety and help reduce non-productive time and invisible lost time. Many of these new sensors provide data at high(er) sampling rates. This has made human monitoring of the data very difficult, if not impossible, and has led to a variety of event detection algorithms. The primary function of these event detection algorithms is to bring the driller's attention to anomalies in the system, based on data collected from all the rig sensors. However, the frequent occurrences of false and missed alarms, when using automated event detection software, can lead to significant downtime, and also reduce safety at the rig. One reason for these false alarms is bad data due to either sensor failure or data communication failure. Having sophisticated sensors, but not knowing whether the data can be trusted, defeats the very purpose of having additional sensors. This paper explores a methodology that can greatly reduce these false and missed alarms by validating the data coming from the sensors.

The data validation methodology described in this paper utilizes a Bayesian network model of the sensed parameters, to maximize the number of analytical redundancies among the parameters. Also, data is collected and aggregated from multiple sources within and outside the rig, such as the well plan, morning reports and real-time data, to obtain increased certainty in the prediction of sensor / process anomalies. The algorithm allows for the detection and isolation of sensor faults and process faults, and does not impose unrealistic assumptions of process invariance. For any type of drilling operation, the parameters in a drilling model are constantly changing. Here, we briefly discuss how the model can be updated in real-time, depending on whether the fault is in the sensor or in the process. The approach is very flexible and easily accommodates the widely varying number of sensors from rig to rig. The methodology can also be easily scaled to be applied on a small subsystem (top drive, hydraulic unit, etc.) or the entire rig (all surface and sub-surface sensors). The proposed methodology is applied on sample scenarios that are typical of the unconventional shale drilling operations conducted in North America.
Open Hole Packers Provide Zonal Isolation for High Pressure Acid Stimulation within a Chalk Reservoir
Authors: Hazel P. , Singh H. , Bårdsen J. , Vasques R. , Pearcy R. , Hannah N.
Published: September 2013

This paper overviews the design, development, qualification, and field trial deployment of a hydraulically expandable metal packer that enabled a cementless, zonal, high-pressure acid stimulation program to be accomplished.

Achieving effective zonal isolation within long reach horizontal wells using conventional means with cement is challenging to the industry. Achieving effective cement within long step outs is limited by the Equivalent Circulation Density (ECD) (impacted by fracture/pore pressure) or by the inability to achieve effective cement (i.e., without channels/micro annuli) simply due to the sheer length of the horizontal section of the well. Additional challenges are then imposed to achieve zonal isolation within unconventional reservoirs or wells that require high-pressure stimulation.

These challenges spurred the design for a metal expandable packer for use in a cementless completion, assembled on a full bore liner, and able to deliver a high annular Delta P seal in a worse case washed-out hole scenario.

Material selection to allow hydraulic expansion beyond the yield point of the expanding alloys (i.e., in the plastic region) is a key design consideration for maximizing the post-expansion strength of the expandable metal packer. Continual design, test, and result analysis enabled development of a unique, high-pressure seal between the metal expansion sleeve and the formation. The qualification process was based on the ISO 14310 V3 standard, the industry standard for testing and qualifying plugs and packers. This standard emulates the lifecycle of the packer during acid stimulation and later-life water management.

Field-proven zonal pressure isolation will be illustrated with real-time zonal pressure data from the field trial in an offshore field. The well will demonstrate cement-less liner completion efficiency with sixteen expandable metal packers to achieve five isolated, stimulated, and subsequently producing zones and three water shut-off zones.

In closing, the paper will summarize ongoing developments and how the open hole expandable metal packer is meeting the unique challenges of annular high-pressure containment. The many benefits to operators include fast setting under surface control with increased reliability and certainty for success.
Upscaling of Miscible Floods: An Extension to Koval's Theory
Authors: Jain Lokendra , Lake Larry W
Published: September 2013

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

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

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

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

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

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

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

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

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

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.
Visual Investigation of Oil Recovery by Low Salinity Water Injection: Formation of Water Micro-Dispersions and Wettability Alteration
Authors: Emadi Alireza , Sohrabi Mehran
Published: September 2013

Low salinity waterflood (LSW) is a relatively new enhanced oil recovery (EOR) technique which has been reported to improve oil recovery in several laboratory experiments and some field trials. The general assumption among researchers is that LSW shifts wettability towards a more favourable state for oil recovery. Several hypotheses have been introduced in the literature as possible mechanisms involved in oil recovery by LSW e.g. fine migration and flow diversion, multi-component ion exchange (MIE), and rise in pH. However, a consistent theory to explain the process of wettability modification has not yet emerged.

This paper presents the results of a comprehensive set of direct visualization (micromodel) experiments which investigate the low salinity effect (LSE) from a novel perspective. The visualization study, using reservoir-condition micromodels, shows that when low salinity brine comes in contact with certain crude oils, a large number of water micro-dispersions form at the oil/water interface within the oil phase. The formation and precipitation of these micro-dispersions can only be seen under high magnifications using our imaging system specifically designed for thin micromodels. The water micro-dispersions do not form when the oil is in contact with a high salinity brine and when they form due to low salinity of the brine, they coalescence as soon as the oil comes in contact with a high salinity brine.

In our micromodel tests, when a mixed-wet micromodel and high salinity connate water were utilized, the formation of these micro-dispersions was associated with a slight change in the wettability and redistribution of fluids. We hypothesize that formation of the micro-dispersions results in additional oil recovery through two separate mechanisms; (1) depletion of the oil/water interface from natural surface active materials, resulting in wettability alteration and, (2) swelling of droplets of high salinity connate water. The results of this study introduce water/oil interactions and formation of water micro-dispersions as a potential mechanism for wettability alteration and improved oil recovery in low salinity water injection.
Modeling Water Flow in Hydraulically-Fractured Shale Wells
Authors: Jurus Wojciech J. , Whitson Curtis Hays , Golan Michael
Published: September 2013

This paper provides an approach to model water injection and production performance observed in horizontal multi-fractured wells using a commercial finite difference (FD) model. Stress dependent permeability is used to ensure that injected rates and volumes during hydraulic fracturing are predicted by the FD model. Varying degrees of water retention observed in shale wells is modeled using gas-water imbibition capillary pressure.

Hydraulic fracturing is used to stimulate shale and other ultra-tight reservoirs. During the treatment tens of thousands barrels of water are injected into a single well, distributed between many (5-30+) fractures. Field experience shows that a significant fraction of injected water never flows back, and the amount depends somewhat on how long the well is shut-in prior to production start.

This study was conducted using a commercial black-oil reservoir simulator. A horizontal well with multiple transverse fractures is modeled. A simple stress dependent permeability model (without hysteresis) has been found to provide sufficient permeability increase during injection to ensure the magnitude of injected water rates and volumes achieved during actual fracturing operations.

Inclusion of water imbibition capillary pressures helps control the amount of water retained by the rock after injection. Capillary forces redistribute injected water further into the rock than if capillarity is ignored. When a well is shut-in prior to flowback, imbibition draws injected water yet further into the rock, reducing water mobility and total recovery of injected volumes when the well starts producing. We study water flowback behavior as a function of water imbibition capillary pressure curves: their magnitude and shape (pore size distribution and wettability).

The mobility of water, as given by relative permeability curves, has an impact on water imbibition and distribution of water in the shale formation near the fracture. It affects the rate of water flowback, but it has a limited effect on total water recovery. We also considered situations with the shale formation initially void of water ("dry" shales), where we find that water recovery is reduced.

Modeling the flow of water in horizontal multi-fractured wells is important to estimate water loss and recovery and the impact on flow performance of hydrocarbons.
Development of Brittle Shale Fracture Network Model - Part 2: What is the Value of SRV?
Authors: Nejad Amir M. , Shelley Robert F. , Lehman Lyle V. , Shah Koras , Gusain Deepak , Conway Matthew T.
Published: September 2013

This paper discusses the workflow for developing a model to predict gas production for hydraulic fracture stages in a brittle shale environment. In our last paper (SPE 163829), we developed a model to predict fracture network geometry (width, length, and height) obtained from microseismic data for various fracture treatment designs. In this study, using both microseismic data and fracture/completion data; frac treatment production is estimated. The well database used for this purpose is comprised of fracture design parameters including treatment volumes, rates, proppant mass and size; well properties include perforation interval length, and perforation depth.

The goal of this study is to provide insight into factors affecting well production in a brittle shale environment. Initial data screening demonstrated massive data scattering and as a result data mining techniques are employed to find possible hidden relationships to explain the nature of the data. Also, using sensitivity analysis on the predictive model, improvements in the current fracture designs and completion schemes in Barnett shale are made.

The database is examined from different aspects using various data mining approaches. After screening and preprocessing the data, non-process affected outlier wells are removed from the dataset. Then, a forward predictive neural network model is trained with fracture design and well data parameters as inputs and well cumulative gas production per stage as outputs. Neural networks are trained with the help of genetic algorithm (GA). The sensitivity study on the trained network provided many insights about well completion and stimulation strategies. Recommendations on how to improve fracture designs and well completion schemes are provided based on sensitivity analysis on the neural networks. Results of neural network modeling in Barnett shale are compared to other gas producing shale assets such as Fayetteville and Haynesville shale to compare the findings.

The results of this work potentially help understanding of completion and fracture treatment designs on well productivity in gas producing shale assets. This will potentially help operators understand how to more effectively design frac treatments and/or reduce the operational costs associated with well completion in a brittle shale environment. Considering the fact that the relationship between stimulated reservoir volume and production is not entirely understood, this work may shed some lights on the aforementioned issue.
Evolution of Dual Fuel Pressure Pumping for Fracturing: Methods, Economics, Field Trial Results and Improvements in Availability of Fuel
Authors: Seybold Elle , Goswick Sam , King George E. , Erickson Brian , Bahorich Mike , Bruchman Mark
Published: September 2013

The displacement of a significant amount of diesel fuel with natural gas during large scale fracturing and drilling developments can be economically feasible in many cases with minor modifications to most diesel engines using dual fuel technology. Dual fuel describes the combination of a pressure and volume regulated stream of natural gas flowing through the engine intake and mixing with a reduced amount of injected diesel fuel in the engine to create power output that is nearly indistinguishable from using straight diesel fuel in high pressure fracturing pumps and other support equipment. Combining diesel fuel and natural gas in a dual fuel system reduces emissions of NOx, SOx, CO2, VOCs and particulates.

Diesel fuel volume has been reduced by as much as 1,575 gallons per frac stage in field testing (63% of total fuel). Engine modification is with primarily bolt-on aftermarket and factory kits. Fuel savings vary depending on price and availability of the natural gas fuel source: LNG (liquid form) from existing liquefaction and/or storage infrastructure or CNG (gaseous form) from local distribution companies (LDC), and/or field gas or distribution gas pipeline systems. Learnings presented from field trials include a case history of frac jobs using CNG, LNG and other gas supply. Economic data is presented on the overall process. Recognition that availability of adequate CNG and LNG fuel supplies may be limiting expanded implementation of dual fuel technologies has prompted us to consider methods of making both fuel supplies more available to other industrial segments as well as the oil and gas industry.