bluuebunny/crossref_metadata_2025 huggingface dataset:
Eagle Ford Shale: Hydraulic Fracturing, Completion, and Production Trends: Part II.
Authors: Centurion Sergio , Cade Randall , Luo Xin Lucy
Published: October 2012

The Eagle Ford Shale, as one of the most active unconventional reservoirs in the US, began heavy development in 2009. One of the attractive aspects of the Eagle Ford, which has heightened interest and helped to accelerate development, is substantial liquids production, along with solution gas. But the resultant multiphase fluid production, along with reservoir heterogeneity, typical of most unconventional reservoirs, adds complexity and risk to development, especially for the completion.

One technique that has the potential for reducing risk is learning from historical completion trends. Even though the Eagle Ford play is quite new, more than 3,000 horizontal wells have been drilled and all have been hydraulically fractured. The resultant large and growing data resource invites data mining to uncover trends and insights.

The ground work was laid in SPE 149258, which summarized 1,082 fracturing stages in 80 Eagle Ford well. This paper extends that analysis to more than 3,000 Eagle Ford fracturing stages in more than 200 wells. Metrics of completion types, volumes, and efficiencies are analyzed. In addition, the analysis is extended to production data and chemical fracturing additives. The entire data set is mapped in an effort to understand anomalies and trends. As the successful development of this reservoir has relied in the combination of horizontal drilling, multistage completions and hydraulic fracturing, the results should be valuable for understanding and optimizing completions in the Eagle Ford and similar shales.
Hydraulic Fracture Geomechanics and Microseismic Source Mechanisms
Authors: Warpinski N. R. , Mayerhofer M. J. , Agarwal K. , Du J.
Published: October 2012

Interpretation of microseismic results and attempts to link microseismic source mechanisms to fracture behavior require an understanding of the geomechanics of the fracturing process. Stress calculations around fractures show that the area normal to the fracture surface is stabilized by a pressurized fracture as a result of increased total stress and decreased shear stress. In this area, microseisms can only occur if leakoff pressurizes natural fractures, bedding planes, or other weakness features, and source mechanisms are thus likely to show a volumetric component. Conversely, the tip tensile region is destabilized by a reduction in total stress and an increase in shear stress, with the likelihood that microseisms would be generated in this region because of these changes. Such microseisms would not yet be invaded by the fracturing fluid, and events that are mostly shear would be expected. Systems with multiple fractures, such as those that are potentially created in multiperforationcluster stages, are much more complex, but similar elements can be outlined for those as well.

Source mechanisms can help delineate these different types of microseismic behaviors, but evaluation of such mechanisms reveals that they provide no significant information about the hydraulic fracture. While it would be valuable if source mechanisms could provide information about the mechanics of the hydraulic fracture (opening, closing, proppant, etc.), calculations show that both the energy and volume associated with microseismicity are an insignificant fraction of the total energy and volume input into the stimulation. Thus, hydraulic fractures are almost entirely aseismic. Analysis of source mechanisms should be concentrated on what that data reveals about the reservoir (e.g., natural fractures, faults, etc.). Integrated diagnostic studies provide more value in understanding both the microseismicity and interpretation of the microseismic results.
Optimizing Perforating Charge Design for Stimulation
Authors: Quattlebaum Clinton C. , Borgen Ken , Xue Zhenyu , Wilkinson Pete
Published: October 2012

Hydraulic stimulation technologies, which are vital in maximizing the production of unconventional reservoirs, have typically focused on pumping capacities and rates, hydraulic fluid viscosities, and proppant materials. A technology that historically has been overlooked, but is critical to an efficient hydraulic stimulation, is the actual perforations through which the treatment is pumped.

Fundamental rock and fracture mechanics demonstrate that perforation shot density, phasing, and hole size affect breakdown and treating pressures and injection rates, and can be a cause of early screenout. Although some of these perforation parameters are considered in the best practices, perforation hole size is often misunderstood.

Complex computer fracture models, used to plan stimulation and completion programs, often incorporate average holediameter values with little consideration of the actual hole sizes or the variance from shot to shot. New research documents how this inconsistency can be considerable when using standard shaped-charge perforators. Nevertheless, perforating charges designed for natural completions, which focus primarily on the depth of penetration, are continuously used before hydraulic stimulation, ignoring the importance of consistent hole size. Advanced simulations using finite element analysis (FEA) have confirmed that fracture placement in a reservoir requiring stimulation would benefit significantly from maintaining consistency in the size of the perforation exit-hole.

This work reviews the analysis performed and the subsequent successful field results for a new class of shaped-charge. The new fracture charge is engineered to maximize hole-diameter while maintaining a consistent exit-hole diameter independent of well profile and/or gun eccentricity. Designed for perforating before a hydraulic stimulation, a fracture charge has been shown to optimize fracturing efficiency and placement by ensuring that each perforation tunnel contributes equally during the fracture treatment, which contributes to providing cost effective hydraulic stimulation and maximizing subsequent asset value.
Flow Rate Prediction in Multilateral Wells Using Distributed Temperature Sensors
Authors: Almulla J. M. , Yang C. , Zhu D.
Published: October 2012

The new advancements in well monitoring tools have increased the amount of data that could be retrieved with great accuracy. The new challenge that we are facing today is to maximize the benefits of the large amount of data provided by these tools. One of these benefits is to utilize the continuous stream of data to determine the flow rate in real time of a multilateral well. Temperature and pressure changes are harder to predict in horizontal laterals compared with vertical wells because of the lack of variation in elevation and geothermal gradient. Thus the need of accurate and high precision gauges becomes critical. A theoretical model is developed to predict temperature and pressure in trilateral wells. The model is used as a forward engine in the study and an inversion procedure is then added to interpret the data to flow profiles. The forward model starts from a specified reservoir with a defined well structure. Pressure, temperature and flow rate in the well system are calculated in the motherbore (main hole) and in the laterals. Then we use the inverse model to interpret the flow rate profiles from the temperature and pressure data measured by the downhole sensors. A gradient-based inversion algorithm is used in this work, which is fast and applicable for real-time monitoring of production performance. In the inverse model, the flow profile is calculated until the one that matches the temperature and pressure in the well is identified. The production distribution from each lateral is determined based on this approach.

Examples are presented in the paper. The value of the model approach for production optimization for trilateral wells is illustrated through parametric study.
An Automated Petrographic Image Analysis System: Capillary Pressure Curves Using Confocal Microscopy
Authors: Al Ibrahim M. A. , Hurley N. F. , Zhao W. , Acero-Allard D.
Published: October 2012

Laboratory mercury injection capillary pressure (MICP) analyses are key inputs into reservoir simulators. Although laboratory MICP measurements are accurate, they are slow, expensive, not friendly to the environment, destroy samples, and are not useful for pore-throats larger than 100 microns. This paper presents a fast and accurate automated petrographic image analysis system, used to compute pore-body and pore-throat size distributions and simulated capillary pressure curves. Input includes high-resolution petrographic images, such as those from confocal microscopy (0.25-microns resolution), and laboratory-derived porosity measurements. Our system can be used in conjunction with laboratory Special Core Analysis (SCAL) to obtain more accurate representations of reservoir properties.

To enable us to compute numerical SCAL measurements, we introduce the Expanding Flow Model (EFM) to show fluid-flow behavior inside pores. This model identifies the largest attached pore-throat as the throat that controls fluid flow in, or out, of a particular pore-body. Pore-throats are extracted using a novel image-analysis technique, based on watershedding algorithms and differences between processed images. We then compute: (a) pore-body and pore-throat size distributions, (b) numerical SCAL in the form of simulated capillary pressure curves for pore bodies and pore-throats, (c) representative element areas (REAs), which are the smallest areas that statistically capture heterogeneity, and (d) values that represent image quality to measure confidence in the results.

We have analyzed a number of samples with different porosity and permeability characteristics. Simulated capillary pressure results show a close match to laboratory data if good-quality representative images and accurate laboratory-derived porosity values are used. Rocks with lower porosity tend to produce better results. Simulated results match raw laboratory data, and eliminate closure-correction factors used in Thomeer capillary-pressure analyses.
A Completion Technology Milestone-The First 25,000 psi 500°F Packer Seal System
Authors: Doane James , Deng Guijun , Collins Scott
Published: October 2012

Increased energy demands for oil and gas have triggered the need to exploit high-pressure/high-temperature (HP/HT) fields, including extreme HP/HT and ultra HP/HT fields. However, well completion of ultra HP/HT fields is posing great technological challenges to operator and service companies. Existing completions technology seems to be reaching its design limits at around the 15,000 psi and 450°F territory.

As operators continue to drill into deeper and more extreme formations, the demand for technologies to suit these environments will steadily increase. Great efforts have been made to overcome the hurdles to develop safe and reliable completion tools qualified for conditions in excess of the 15,000 psi and 450°F territory across the industry over the years. A technological milestone was recently set in packer seal system development—the first 25,000-psi 500°F packer seal system.

Qualification testing was conducted with nitrogen to all the rating envelope points at 500°F with a cool down to 250°F.

The packer seal system passed all tests with no visible seal element extrusion, and no leaks were detected at any of the load points during testing.

This paper presents how this innovative seal system design evolved from several field-proven HP/HT seal systems, and how technological challenges are addressed by adopting state-of-the-art materials and design processes. The paper includes information about conceptual design, design optimization using finite element analysis (FEA), material characterization for both metallurgical and seal material, and seal assembly manufacturing. The qualification testing processes for this 25,000-psi 500°F packer seal system are also described, along with the market potential for these ultra-HP/HT wells.
Surveillance of Complex Displacement Mechanisms in Mature Reservoirs to Maximize Recovery
Authors: Zett Adrian , Webster Mike , Rose Hilary , Riley Steve , Trcka Darryl , Kadam Nilesh
Published: October 2012

The Columbus basin offshore Trinidad is a mature hydrocarbon province. It contains multiple, stacked, discrete reservoirs which are supported and driven by complex displacement mechanisms. The reservoir surveillance challenges in the basin are compounded by the interaction of low salinity formation water, multiple fluid phases, thin beds, and completions that present difficult conditions for cased hole reservoir monitoring instruments.

Challenging current monitoring practices resulted in the implementation of new strategic measurements in the surveillance plan that delivered valuable insights and clarity to complex reservoir management problems.

The results obtained using existing procedures and technologies highlighted their shortcomings and uncertainties. To address these issues emerging technologies were evaluated under these challenging conditions. The results obtained clearly prove that tangible benefits could be realized through the use of the new surveillance techniques.

The benefits of applying new technology as part of an integrated surveillance strategy will be described in this paper. This new approach has helped reduce the uncertainty in both fluid contact movement and remaining hydrocarbon saturations. This has had a direct impact on reservoir simulation and the definition of future reservoir targets.
ESP Technology Maturation: Subsea Boosting System With High GOR and Viscous Fluids
Authors: Barrios L. , Scott S. , Rivera R. , Sheth K.
Published: October 2012

This paper provides insight into the Caisson ESP Technology Maturation for subsea boosting systems with high GOR and viscous fluids. It will focus on the developmental research on the effects of viscosity and two phase (liquid & gas) fluids on electric submersible pumps (ESPs), which are multistage centrifugal pumps for deep boreholes.

The Electrical Submersible Pump (ESP) system is an important artificial lift method commonly used for subsea boosting systems. Multiphase flow and viscous fluids cause problems in pump applications. Free gas inside an ESP causes many operational problems such as loss of pump performance or gas lock conditions (Barrios 2010 [6]). The objective of this study is to predict the operational conditions that cause degradation and gas lock. This paper provides a summary on the Technology maturation for a high scale ESP Multi-Vane Pump (MVP) for high GOR fields to in support of Shell's BC-10 developments. These novel projects continue the long tradition of Shell's leadership in the challenging deepwater environment. This paper will describe the capability and effects of viscosity and two phase (liquid & gas) fluids using a MVP 875 series G470 as a charged pump in a standard ESP system 1025 series tandem WJE 1000 mixed-type pump.

Extensive testing and qualification of the subsea boosting system was undertaken prior to field considerations. Testing was conducted at the world's only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures. A comprehensive suite of tests was performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and performance requirements for Shell's deepwater assets. This paper describes the subsea boosting system maturity process, and reports the effects of viscosity and two phase liquid - gas fluids on ESPs. The test facility work was performed using pumps with ten or more stages moving fluids with viscosity from 2 to 400 cP at various speed, intake pressure, and gas void fractions (GVF, aka gas volume fractions). The testing at Shell's Gasmer facility revealed that the MVP-ESP system is robust and performance tracked theoretical predictions over a wide range of two-phase flow rates and light-viscosity oils
Accurate Microseismic Event Location Inversion Using a Gradient-Based Method
Authors: Li Gaoming , Chen Jingyi , Han Mei , Gajraj Allyson , Xing Yang , Wu Furong , Liu Hong , Yin Chen
Published: October 2012

From the microseismic data collected during multi-stage hydraulic fracturing, we may pick out the first arrival times for both P- and S-waves for each event and at each geophone. With triaxial geophones, the azimuths of the events may be derived from the hodograms. The P- and S-wave arrival times contain the distance information from the event location to the geophones as well as the event initiating time. The azimuth from hodograms gives the orientation information of the event locations. Inverting these interpreted microseismic data yields the event location parameters, which can be used to characterize the hydraulic fractures for reservoir modeling. This paper presents an efficient gradient-based microseismic event location inversion method. The forward model that is used to calculate the first arrival times is the finite-difference solution of the Eikonal equation. A novel method is devised to obtain the gradient of the first arrival times to the event location parameters in addition to the first arrival times in one forward model run. The method is applied to a realistic multilayer shale gas reservoir with a horizontal well and several stages of hydraulic fractures. The results show that the first arrival times obtained from the surface geophones yield better event location parameter estimation assuming we can pick up the events from the surface geophone signal. When the geophones are placed downhole in nearby wells, the inverted event locations are less accurate than the ones with surface geophones but can have a relative good characterization fo the fracture propagation.
Advanced Wireline Formation Tester Applications in Challenging Rocks and Environments
Authors: Omokaro Felix , Musharfi Nedhal , Zeybek Murat
Published: October 2012

Carbonate formations are highly heterogeneous with variations from grainstones to mudstones. Digenesis leads to changes of the rock's original nature, like dolomitization, vugs, layering and fracturing. These variations have effects on rock quality in terms of porosity and permeability. Similarly, clastics, including shaly sands, can be quite challenging in terms of accurate formation evaluation.

Although extensive logs are run for the petrophysical evaluations in these formations, the use of advanced wireline formation testers (WFTs) greatly aids reservoir description. Standard formation evaluation tools and techniques sometimes result in low level of confidence in identifying and quantifying the presence of hydrocarbon in certain reservoirs. The application of modern wireline formation testers has become a useful tool in minimizing uncertainties in situations where we have low confidence in log evaluation. Some borehole conditions and reservoir architectures, like fractures, vugs, and low mobility and mud losses could also pose some challenges while performing formation testing.

In this paper, several examples and case histories of the application of advanced wireline formation testers across varieties of rocks with fractures, vugs and different borehole conditions are presented. Results indicate that reservoir heterogeneities can be described and quantified more accurately with the integration of dynamic data to aid reservoir characterization. This paper also demonstrates how to handle the challenges of detecting the early traces of hydrocarbon arrival for real time decisions during pressure testing and sampling.
Engineering Analysis of Hand Union Connections in Coiled Tubing Operations
Authors: Barraez R. , Yeung T.
Published: October 2012

In an effort to enhance well intervention efficiency while still ensuring safe operations, the mechanical implications of using a quick connect hand union between the wellhead and the coiled tubing blowout preventer to reduce rig-in and rig-out time during coiled tubing operations were explored. The study was conducted in order to support an application to the local regulatory body, requesting that an exemption to standard operating regulations be granted for the proposed procedure.

To complete the study, the locations where maximum tension and compression forces exist during a typical coiled tubing operation were identified. Finite element analysis was then used to simulate and compare the stress distribution in both hand union and flanged type connections. Load cases were based on conditions typically seen during coiled tubing operations.

This paper presents the results of the study. The areas of maximum stress and the calculated safety factor based on the material yield strength of both the hand union and flanged connections for every scenario under given loading conditions are shown. The paper also outlines how the engineering analysis defined the loading limitations in order to safely incorporate the hand union connection as part of the rig-up procedure for coiled tubing operations.
Rock Classification from Conventional Well Logs in Hydrocarbon-Bearing Shale
Authors: Popielski Andrew C. , Heidari Zoya , Torres-Verdín Carlos
Published: October 2012

This paper introduces a rock typing method for application in hydrocarbon-bearing shale (specifically source rock) reservoirs using conventional well logs and core data. Source rock reservoirs are known to be highly heterogeneous and often require new or specialized petrophysical techniques for accurate reservoir evaluation. In the past, petrophysical description of source rock reservoirs with well logs has been focused to quantifying rock composition and organic-matter concentration. These solutions often require many assumptions and ad-hoc correlations where the interpretation becomes a core matching exercise. Scale effects on measurements are typically neglected in core matching. Rock typing in hydrocarbon-bearing shale provides an alternative description by segmenting the reservoir into petrophysically-similar groups with k-means cluster analysis, which can then be used for ranking and detailed analysis of depth zones favorable for production.

A synthetic example illustrates the rock typing method for an idealized sequence of beds penetrated by a vertical well. Results and analysis from the synthetic example show that rock types from inverted log properties correctly identify the most organic-rich sections better than rock types detected from well logs in thin beds. Also, estimated kerogen concentration is shown to be the most reliable property in an under-determined inversion solution.

Field cases in the Barnett and Haynesville shale gas plays show the importance of core data for supplementing well logs and identifying correlations for desirable reservoir properties (kerogen/TOC concentration, fluid saturations, and porosity). Qualitative rock classes are formed and verified using inverted estimates of kerogen concentration as a rock-quality metric. Inverted log properties identify 40% more of a high-kerogen rock type over well-log based rock types in the Barnett formation. A case in the Haynesville formation suggests the possibility of identifying depositional environments as a result of rock attributes that produce distinct groupings from k-means cluster analysis with well logs. Core data and inversion results indicate homogeneity in the Haynesville formation case. However, the distributions of rock types show a 50% occurrence between two rock types over 90 ft vertical-extent of reservoir. Rock types suggest vertical distributions that exhibit similar rock attributes with characteristic properties (porosity, organic concentration and maturity, and gas saturation).

The interpretation method considered in this paper does not directly quantify reservoir parameters and would not serve the purpose of quantifying gas-in-place. Rock typing in hydrocarbon-bearing shale with conventional well logs forms qualitative rock classes which can be used to calculate net-to-gross, validate conventional interpretation methods, perform well-to-well correlations, and establish facies distributions for integrated reservoir modeling in hydrocarbon-bearing shale.
Novel Design and Implementation of Kuwait's First Smart Multilateral Well with Inflow Control Device and Inflow Control Valve for Life-cycle Reservoir Management in High Mobility Reservoir, West Kuwait
Authors: Das Om Prakash , Al-Enezi Khalaf , Aslam Muhammad , El-Gezeeri Taher , Ziyab Khalid , Fipke Steven R. , Ewens Steven
Published: October 2012

Increased hydrocarbon recovery and accelerated production from ultra-high water mobility oil-wet reservoir requires the application of advanced well completion technologies to address premature water breakthrough, reservoir management, production management and extended reservoir contact from a single well location. The Burgan Reservoir of Minagish Field, West Kuwait has active aquifer, very high permeability sands associated with active faults and contain highly viscous reservoir fluid with downhole viscosity of 40cp, enhances water mobility and resulted in premature water breakthrough with increasing water cut trend within few months of production as confirmed from well performance of existing horizontal wells. This has resulted in to non-uniform reservoir depletion, by-passed oil regions and low oil recovery.

The Kuwait's first smart level-4 multilateral well was completed in Burgan reservoir by combining the Level-4 junction along with stacked dual lateral completion having customized viscosity independent Inflow Control Device (ICD), customized two Inflow-Control Valves as well as down hole gauges, wide operating range Electrical submersible Pump (ESP), suitable wellheads, X-MAS tree and Integrated surface panel for real time data monitoring.

The smart multilateral well has assisted in addressing premature water breakthrough, enhanced dry oil production and facilitated uniform depletion, which results in improved hydrocarbon recovery. The paper covers the customized design of smart Level-4 multilateral well by taking in to account the reservoir and its fluid characterization, well architecture, implementation and specially designed invert emulsion drilling fluid for effective wellbore cleanup to achieve formation virginity. The improved reservoir management and production management results are also mentioned in this paper.
Analytical Model to Estimate the Downhole Temperatures for Casing while Drilling Operations
Authors: Kumar Aniket , Samuel Robello
Published: October 2012

The benefits of casing while drilling have become apparent to the industry as complex wells are drilled through depleted reservoirs. Casing while drilling operations help to reduce lost circulation, provide wellbore strengthening, mitigate formation damage, and eliminate non-productive time (NPT). The plastering effect mechanism responsible for pulverizing and smearing the cuttings in the formation to increase the fracture gradient is under extensive research to effectively realize the above benefits. An analytical model used to predict the temperature of the drilling fluid downhole while drilling with a casing will provide an improved understanding of this plastering effect. An estimate of the downhole temperature increases attributable to the persistent contact between the casing and the borehole wall, a characteristic of casing while drilling, will add to the ongoing quantitative analytical studies.

This study proposes an analytical model to analyze the heat generated from the contact between the casing and the borehole wall during a casing while drilling operation and predicts the downhole temperatures of the drilling fluid at any depth of the well. The torque acting on the casing as a result of contact forces was used to model the heat generated, and a steady- state heat transfer solution is presented. The model also incorporates the heat dissipated downhole as a result of frictional pressure losses along the drillpipe, casing, and bottomhole assembly (BHA), as well as energy dissipated through pressure losses across the bit.

The paper presents four practical casing while drilling field cases to suggest potential applications for the proposed model. Downhole temperatures of the drilling fluid were calculated along the well profile, and the increase in mud temperature along the target zones was estimated. The effect of the increase in downhole mud temperatures while drilling with a casing is then analyzed in the context of improving the fracture gradient attributable to the plastering effect. In addition, the effect of drilling parameters on the increase in fracture gradient has also been presented. This simple analytical model can be applied to casing while drilling operations to enhance our understanding of the plastering effect and to use it to our advantage.
Evaluation of Established Perforation Cleanup Models on Dynamic Underbalanced Perforating
Authors: Haggerty Dennis , Craddock G. G. , Quattlebaum Clinton C.
Published: October 2012

The process of perforating in an underbalanced condition has, for many years, been a widely accepted method for ensuring open, clean, and clear perforation tunnels that are conducive to reservoir flow. With the increased popularity of tubing- conveyed perforating (TCP) during the last several decades, this method and the ability to maximize the amount of pressure differential has become even more popular and is often the preferred completion technique. In the last few years, an enhancement to underbalanced perforating, commonly known as dynamic underbalanced perforating, has been examined both through experiments and models. Dynamic underbalanced perforating is a process that creates a negative pressure differential or underbalance, causing fluid to move toward the wellbore even in an initial overbalanced static condition. A dynamic underbalanced condition can be controlled by understanding and carefully managing the temporal pressure transients, using multiple methods within the wellbore during and after gun system detonation. However, fundamental questions remain: What dynamic underbalanced behavior and pressures are required to remove the perforation-crushed zone, and are existing cleanup models sufficient for predicting perforation cleanup given the reservoir condition?

Recently, a series of instrumented perforation experiments using an advanced perforation flow laboratory demonstrated that existing cleanup models do not accurately predict perforation cleanup when perforating in a dynamic underbalanced condition. This work presents initial data and analysis, and suggests a superior method for quantifying perforation cleanup for a given dynamic underbalanced behavior and reservoir condition.
Evaluation of the Carbon Dioxide Response on Pulsed Neutron Logs
Authors: Quinlan Tim , Sibbit Alan , Rose David , Brahmakulam Jacob , Zhou Tong , Fitzgerald John , Kimminau Steve
Published: October 2012

Carbon Dioxide (CO2) sequestration and enhanced recovery projects require the evaluation of rocks containing mixtures of CO2, water, and gaseous or liquid hydrocarbons. Pulsed neutron logs of various designs and measurement types have been used since the 1960s to evaluate formations containing gaseous hydrocarbons, but they were not originally designed or characterized specifically for quantitative CO2 evaluation. Computer modeling, test pit data, and field examples are presented in this work to highlight the issues of CO2 evaluation and to compare these with gaseous hydrocarbons.

Pulsed neutron tools emit 14 MeV neutrons from an accelerator source, but a wide variety of timing sequences, detector types, source-detector spacings, and signal processing techniques are employed by the industry to extract formation description parameters from the recorded counts. For the non-specialist petroleum engineer this variety can confuse and distract from effective use of the measurements. We organize all categories of pulsed neutron logs into simple types based upon the measurement physics to provide an effective guide to field use of these logs.

Examples of commercial and experimental tools in clastic and carbonate environments are presented. The examples show how CO2 can be quantified and demonstrate critical design requirements for successful pulsed neutron logging campaigns. We outline the lessons learned and make recommendations for the design of logging programs and interpretation of the acquired data in stand-alone or in time-lapse modes.
Modeling of Wettability Alteration Due to Asphaltene Deposition in Oil Reservoirs
Authors: Darabi Hamed , Sepehrnoori Kamy , Kalaei Mohamad Hosein
Published: October 2012

Wettability is a key property, which controls multiphase fluid flow in oil recovery processes. It is well known that the asphaltene deposition on rock surface changes the wettability of the rock. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration in crude oil/brine/rock (COBR) system because of asphaltene deposition; a sophisticated mathematical model describing this phenomenon is absent.

In this paper, based on available experimental data in the literature and known physical mechanisms of asphaltene deposition on the rock in the COBR system, a model for wettability alteration due to asphaltene instability in crude oil is presented. Contact angle is introduced as a function of asphaltene stability index (ASI), which is determined thermodynamically based on the difference between the fugacity of asphaltene and the heaviest component in the oil. The shape of this function depends on pH, salinity and cation valency of brine, and asphaltene content of crude oil. We implemented our proposed model along with asphaltene precipitation, flocculation, and deposition models into an in-house compositional simulator, UTCOMP, developed at The University of Texas at Austin. Permeability and porosity reduction due to asphaltene deposition are also considered. Furthermore, relative permeabilities and capillary pressure are modified because of contact angle alteration during simulation.

Although the amount of asphaltene deposition in the reservoir may not be comparable to the wellbore, a significant change in wettability occurs after the deposition of first layer of asphaltene on the rock surface. The result of our simulation shows that wettability alteration affects oil recovery, specifically when the brine produces unstable water film on the rock surface. In this case, rock wettability can change from 30° (water-wet) to 150° (oil-wet) and yield change in recovery depending on absolute permeability reduction magnitude and change in trapped oil saturation as well as end-point relative permeability.
New Pressure-Actuated Valve Allows for Interventionless Access to Formation in Cemented Applications
Authors: Johnson C. Christopher , Kellner Justin , Mailand Jason
Published: October 2012

Unconventional reservoirs require innovative completion techniques and technology to become more economical. Formations vary drastically in lithology, lateral lengths, completion methods, and financial drivers. One of the most common techniques is the ‘plug-n-perf’ method. In the Eagle Ford, long-string completions are the norm, with the production casing cemented in place along the horizontal section and up the vertical section, providing isolation between frac stages and from other formations above and below the zone of interest.

The Eagle Ford shale is a formation that produces gas, liquids, and oil, depending on the area in South Texas being drilled. Operators are looking for ways to reduce cost and gain efficiencies when completing wells in unconventional reservoirs. One way of reducing cost is eliminating coiled-tubing-deployed perforations for establishing reservoir communication on the first stage of multistage frac operations.

Technology has been developed which provides operators the option of placing a pressure-actuated valve above the shoe track, allowing for standard cementing practices. The new valve provides operators the ability to pressure test the casing and, through the use of applied pressure from the surface, activate into the open position. Once opened, information about the reservoir can be gathered that will influence the frac design before assembling the required pumping equipment.

This paper presents multiple case histories showing different applications of the cemented pressure-actuated valve. The development history, reliability, and inherent accuracy are presented. This interventionless access technique has been proven effective in the Eagle Ford and Haynesville formations and is applicable in other unconventional reservoirs requiring multistage hydraulic fracturing.
Portfolio Optimization in High and Low Risk Environments
Authors: Rodriguez Luis , Moreland Brian , Kirk Graham
Published: October 2012

Upstream oil and gas is a very capital intensive business. Shareholders look for profitability and growth against a backdrop of declining production and decreasing new play sizes. Optimal project selection is necessary to maximize the potential of any portfolio or business plan. The main goal of a Business Plan is to select a portfolio of projects (drilling, exploration, etc.) that maximizes value (and minimizes risk) and satisfies all constrains faced by management (drilling rig availability, facilities capacity, capital availability, human resource availability, etc.)

These problems can be expressed in the form of a set of linear or non/linear equations such that global optimum values can be determined using Linear Programming or Genetic Algorithms. In this paper we will show how these techniques can be used to solve optimization problems utilizing a combination of both techniques and the use of software designed for that purpose.

In our case study, we were able to define and implement a plan that increased expected production, reduced capital requirements by 20%, kept the activity within the capacity of the drilling rigs and facilities available and clearly prioritized the proven undevelop reserves within a maximum of 5 years for planned development. The total time invested on designing the plan was less than 5 days and the execution became clear to all the parts involved via a tool to share the information. The plan as designed was executed in 2011 flawlessly.
A Decade of Deepwater Gulf of Mexico Stimulation Experience
Authors: Morgenthaler Lee N. , Fry Leigh A.
Published: October 2012

The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rate and ultimate recoveries per well are required to offset high development costs. Stimulation is employed to maintain wells at peak production rates and accelerate reserve recovery. In the complex layered reservoirs of the deepwater Gulf of Mexico stimulation is also necessary to ensure volume recovery. The primary objective of stimulation is to restore impaired well /reservoir connectivity. In complex reservoirs this may be reflected in either a reduction of skin or improvement in apparent permeability height. In poorly consolidated sandstone reservoirs production may become impaired during completion operations by suspended solids, polymer residue, or incompatible fluid systems. During production fines migration, scale deposition, and organic deposits in the near wellbore and sand control system can lead to declining inflow performance. Successful identification of the cause and location of impairment is required for success. The increasing population of subsea wells creates new challenges for intervention. Correct operation of the well post stimulation is also necessary to achieve the desired rate increases without compromising production system performance. The nature of impairment, treatment options, and post treatment production issues often change over the life of the well. Looking back over a decade of experience in this challenging environment yields useful insights as we move into new deepwater provinces.
Evaluating an Engineered Completion Design in the Marcellus Shale Using Mircoseismic Monitoring
Authors: Wutherich Kevin , Walker Kirby , Aso Iroh , Ajayi Babatunde , Cannon Tom
Published: October 2012

It has long been accepted that one of the most cost-effective strategies for completing a horizontal shale gas well is to pump several fracture stimulation treatments along the lateral with each treatment contacting several perforation clusters spread out over a few hundred feet. Typically, these clusters are placed geometrically from toe to heel with the same distance between clusters and no other consideration as to the location of these perforations.

While this process simplifies the design of the completion, there are indications that this can be ineffective in contacting the maximum amount of reservoir. The fracture treatment will tend to follow the path of least resistance; intervals where stresses are the lowest will be preferentially stimulated over intervals that have higher stress concentrations. This effect was very clearly seen in a recent stimulation campaign performed in the Marcellus shale. During the fracturing treatments on several laterals, large gaps in microseismic events were observed where some perforation clusters appeared to take little to no fluid. Outlined in this paper is one particular example where even with use of a very aggressive limited-entry perforating technique, which uses perforation friction pressure to help distribute flow equally to each perforation, microseismic monitoring still showed 35% of the clusters receiving no fluid.

To improve stimulation coverage, two completions were designed using data acquired from horizontal well logs. Interpretations of lithology and stress along the wellbore allowed perforation selection in these wells using a newly developed software platform in such a way that the induced fractures were afforded the best chance of distributing equally along the lateral. Microseismic monitoring obtained during the stimulation of these wells clearly indicated significantly better fracture coverage. Additionally, stimulation treating pressures were reduced by targeting lower stressed sections, resulting in less difficulty placing proppant.
Laboratory and Field Evaluation of Proppants and Surfactants used in Fracturing of Hydrocarbon Rich Gas Reservoirs
Authors: Penny Glenn , Zelenev Andrei , Long Wei , Lett Nathan , Crafton James
Published: October 2012

The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower the effective conductivity even for the portions of the fracture above the wellbore.

Laboratory and field studies are presented comparing various sizes and types of proppants and the influence of surfactants used in oil bearing formations including commonly used demulsifiers and a multi-phase complex nano fluid system. Ammot cell and centrifuge tests were used to evaluate imbibition of oil and water. Columns packed with proppant and formation cuttings are used to compare the effectiveness of various additives in allowing the displacement of water and establishing oil flow. Results are correlated with interfacial tension, contact angle, capillary pressures and surface energies of actual formation materials, oils and treating fluids from the Niobrara, Bakken, Granite Wash and Eagleford formations. Simulations are presented that show the impact of capillary pressure and oil viscosity on the displacement of fluids.

Field results from various fields including the Niobrara, Bakken, and Marcellus formations are presented. The normalized field data shows that wells with higher conductivity proppants and properly selected surfactant packages result in longer effective frac lengths and greater normalized oil and gas production. Correlations are made between the observed relative perms in the lab vs. the observed field results.
Improving Well-Performance-Data Analysis in Laplace Space by Using Cubic Splines and Boundary Mirroring
Authors: Ahmadi M. , Gonzalez O. G. , Ozkan E. , Parsa S. E.
Published: October 2012

Despite unequivocal advantages of using sampled well-performance data in the Laplace transform domain, time-domain analysis of pressure and production data have been more popular lately. This is because of the unresolved problems in the transformation of sampled data to Laplace domain as opposed to the demonstrated success of the recent real-time deconvolution algorithms. However, the transformation of sampled data to Laplace domain has a broader range of applications than deconvolution and the limited success of the past approaches to transform tabulated data to Laplace domain, such as piece-wise linear approximations, is an algorithmic issue; not a fundamental defect. Specifically, an adequate algorithm to transform the piecewise-continuous sampled data into the Laplace space and an appropriate numerical Laplace inversion algorithm capable of processing the exponential contributions caused by the tabulated data are essential to exploit the potential of Laplace domain operations.

In this paper, we introduce a new algorithm which uses inverse mirroring at the points of discontinuity and adaptive cubic splines to approximate rate or pressure versus time data. This algorithm accurately transforms sampled data into Laplace space and eliminates the Numerical inversion instabilities at discontinuities or boundary points commonly encountered with the piece-wise linear approximations of the data. The approach does not require modifications of scattered and noisy data or extrapolations of the tabulated data beyond the end values.

Practical use of the algorithm presented in this paper has applications in a variety of Pressure Transient Analysis (PTA) and Rate Transient Analysis (RTA) problems. Our renewed interest in this procedure has arisen from the need to evaluate production performances of wells in unconventional reservoirs. With this approach, we could significantly reduce the complicating effects of rate variations or shut-ins encountered in well-performance data. Moreover, the approach has proven to be successful in dealing with the deconvolution of highly scattered and noisy data. To illustrate the applications, typical field examples, including shale-gas wells, are presented in the paper.