bluuebunny/crossref_metadata_2025 huggingface dataset:
Propagation Measurements for Acoustic Downhole Telemetry Systems
Authors: Farraj Abdallah K. , Miller Scott L. , Qaraqe Khalid A.
Published: June 2014

Advanced downhole communication technologies are used by well operators to monitor flow rate, temperature, and pressure data. Currently, the use of wired tools is popular although these tools present cost, maintenance, and reliability issues. Acoustic waves that propagate by vibrating the pipe's body inside the well are investigated as an alternative solution. While this technology offers great benefits, its propagation aspects inside the wells are unclear.

This work explores the use of acoustic waves for downhole telemetry systems. A testbed was designed to investigate the propagation of acoustic waves over production pipes. The testbed comprises an acoustic tool that transmits data from inside wellbore to the surface without cables, an internally-developed receiver unit, and five segments of 7-inch production tubing that form a pipe string. Acoustic waves propagate by vibrating the pipe's body in this setup. Input frequencies from 100 Hz to 2000 Hz were investigated, and propagation measurements were taken along the pipe string. Further, the application of signal processing techniques is investigated to address the effects of dispersion and attenuation in the acoustic channel.

Results of this work show that many harmonics propagate through the pipe string. Acoustic waves experience a frequency-dependent attenuation over the pipe string. Multipath reflections in the pipe string also cause noticeable signal dispersion. This work also shows that acoustic waves experience an extra frequency-dependent attenuation due to the presence of concrete; many high-order harmonics are heavily attenuated after encasing the pipe in concrete. Moreover, signal processing algorithms provide pronounced results in reducing the channel attenuation and dispersion. This work recommends that acoustic-wave technology is a promising cost-effective and reliable solution for wireless downhole telemetry systems. Furthermore, signal processing algorithms can be useful tools for the acoustic downhole communication systems.

Technical contributions include: characterizing the channel response to different input frequencies along the pipe string; investigating the power spectral density, signal-to-noise ratio, and attenuation rate measures; studying the dispersion parameters of the channel; characterizing the effect of concrete on acoustic wave propagation; and applying signal processing algorithms.
Using Big Data and Smart Field Technology for Detecting Leakage in a CO2 Storage Project
Authors: Haghighat S. Alireza , Mohaghegh Shahab D. , Gholami Vida , Shahkarami Alireza , Moreno Daniel
Published: June 2014

Smart Fields are distinguished with two characteristics: Big Data and Real-Time access. A small smart field with only ten wells can generate more than a billion data points every year. This data is streamed in real-time while being stored in data historians. The challenge for operating a smart field is to be able to process this massive amount of information in ways that can be useful in reservoir management and relevant operations. In this paper we introduce a technology for processing and utilization of data generated in a smart field. The project is a CO2 storage demonstration at Citronelle Dome, Alabama and the objective is to use smart field technology to build a real-time, long-term, CO2 Intelligent Leakage Detection System (ILDS).

The main concern for geologic CO2 sequestration is the capability of the underground carbon dioxide storage to confine and sustain the injected CO2 for very long time. If a leakage from a geological sink occurs, it is crucial to find the approximate location and amount of the leak in order to take on proper remediation activity.

To help accommodate CO2 leak detection, two PDGs (Permanent Down-hole Gauges) have been installed in the observation well. A reservoir simulation model for CO2 sequestration at Citronelle Dome was developed. Multiple scenarios of CO2 leakage are modeled and high frequency pressure data from the PDGs in the observation well are collected. The complexity of the pressure signal behavior and the reservoir model makes the use of inverse solution of analytical models impractical. Therefore an alternate solution is developed for the ILDS, based on Machine Learning.

High Frequency Data Streams are processed in real-time, summarized (by Descriptive Statistics) and transformed into a format appropriate for pattern recognition technology. Successful detection of location and amount of CO2 leaking from the reservoir using the real-time data streams demonstrates the power of pattern recognition and machine learning as a reservoir and operational management tool for smart fields.
Probabilistic Reserves Addition within a Project
Authors: Morales E. , Horizon B. V. , Lee W. J.
Published: June 2014

The SPE-Petroleum Resource Management System (SPE-Petroleum Resources Management System, 2007) is a project based system, where the project definition and its treatment play a key role in the estimation and categorization of reserves and resources and their range of uncertainty. This is key to capture the potential downside and upside of the project and the commercial opportunities that may exist. Wrongly defining the project may result in an improper ring-fencing of the elements that must be considered in reserves and resource estimation and in improper risk assessment, with potential for missed opportunities or failure as an outcome.

The SPE-PRMS is clear on the type of aggregation that can be used within a field, a property or a project, with probabilistic addition allowed within each of these entities. However, despite this clarity, most companies in the oil and gas industry have not yet adapted their methods to reflect these best practices.

The technical literature has devoted significant effort to address technical and commercial issues in probabilistic reserves and resource estimation of a field or incremental activity (e.g., drilling wells). However, very little effort has been devoted to the proper definition of a "project", its attributes, ring-fencing, uncertainty assessment approaches for the fields within the project and in the categorization and aggregation of reserves or resources within the project.

Furthermore, downside project economics should capture the true project's downside (or the true P90 of the project) rather than an overly-pessimistic estimate of its proved reserves calculated using arithmetic additions within the project.

In order to describe a simple approach to project reserves estimates, this paper uses a Liquefied Natural Gas (LNG) project and its reserves estimate as an example. The selected example shows different interpretations among joint venture (project) partners of the existing standards, recommendations and regulations. The approach described can also be used in other types of projects or resources estimates (e.g. contingent resources), to properly capture the downside and upside risks, uncertainty ranges and project business opportunities, truly reflecting the project's reasonable certainty at the P90 level. Gas projects are preferred to illustrate this approach.

For gas commitment purposes, many buyers require the LNG project's proved (P90) reserves to be independently certified before contractual commitments can be finalized. Underestimation of the project's true proved reserves may result in loss of opportunities and/or in an overly-pessimistic assessment of the Proved reserves not reflecting reasonable certainty.

Requirements from regulatory bodies (e.g., NARA (SEC), 2009; ESMA, 2011) and their linkages to reserves aggregation within a project are also addressed in this paper.
Casing While Drilling Utilizing Rotary Steerable Technology in the Stag Field-Offshore Australia
Authors: Graves Kyle S. , Herrera Gomez Delimar Cristobal
Published: June 2014

Originally discovered in 1993, the Stag Oil Field, located on the Northwest Shelf of Western Australia, has produced over 58 MMbbls since production began in 19987. The Field is a shallow (680m SS), highly unconsolidated, highly permeable sandstone. Reservoir depletion, unconsolidated rock, water breakthrough and sand production have created conditions where infill drilling campaigns have become increasingly problematic in the Stag field in recent years. Numerous papers have documented the history of the Stag Field's colorful past12-13, 23.

On three recent infill wells the intermediate 12 ¼?? intervals were drilled and cased using Casing while Drilling (CwD) technology using a rotary steerable system. This was used to navigate wellbore congestion, drill designer wellpaths to avoid "incoherencies?? (a seismic attribute that is mappable and correlates with drilling problems5), land the horizontal section and then drill horizontal tangent sections out to the initial reservoir penetration (liner point). The CwD applications progressed from a "new technology?? trial to a stretch reach and performance goal, to finally successfully being used a key enabling technology to drill a well that might otherwise be undrillable due to instability issues.

The directional CwD 12 ¼?? hole intervals were drilled from just below the 13 3/8?? surface casing to the 9 5/8?? casing point, building from 25 degrees inclination to horizontal and holding thereafter. This program (the first applications of this type in Australia) resulted in two consecutive world record runs. The result is that CwD is a viable enabling technology that will be used to drill future Stag infill and should be considered as a viable alternative on other drilling projects.

This paper will discuss the identification of the technology application, planning, implementation, results and lessons learned. This paper will end with a notional conversation regarding CwD becoming a mainstream method.
A New Approach for the Simulation of Fluid Flow in Unconventional Reservoirs through Multiple Permeability Modeling
Authors: Yan Bicheng , Alfi Masoud , Wang Yuhe , Killough John E.
Published: June 2014

Shale reservoirs are characterized by ultra-low permeability, multiple porosity types, and complex fluid storage and flow mechanisms. Consequentially the feasibility of performing simulations using conventional Dual Porosity Models based on Darcy flow has been frequently challenged. Additionally, tracking of water in shale continues to be controversial and mysterious. In organic-rich shale, kerogen is generally dispersed in the inorganic matter. Kerogen is different from any other shale constituents because it tends to be hydrocarbon-wet, abundant in nanopores, fairly porous and capable of adsorbing gas. However, the inorganic matter is usually water wet with low porosity such that capillary pressure becomes the dominant driving mechanism for water flow, especially during hydraulic fracturing operations. This work presents a technique of subdividing shale matrices and capturing different mechanisms including Darcy flow, gas diffusion and desorption, and capillary pressure. The extension of this technique forms a solid and comprehensive basis for a specially-designed simulator for fractured shale reservoirs at the micro-scale.

Through the use of this unique simulator, this paper presents a micro-scale two-phase flow model which covers three continua (organic matter, inorganic matter and natural fractures) and considers the complex dynamics in shale. In the model, TOC is an indispensable parameter to characterize the kerogen in the shale. A unique tool for general multiple porosity systems is used so that several porosity systems can be tied to each other through arbitrary connections. The new model allows us to better understand the complex flow mechanisms and to observe the water transfer behavior between shale matrices and fractures under a microscopic view. Sensitivity analysis studies on the contributions of different flow mechanisms, kerogen properties, water saturation and capillary pressure are also presented.
Geological Attributes from Conventional Well Logs: Relating Rock Types to Depositional Facies in Deepwater Turbidite Reservoirs
Authors: Xu Chicheng , Torres-Verdín Carlos , Steel Ronald J.
Published: June 2014

Grain size and bed thickness are important geological attributes for sedimentary facies analysis and reservoir quality ranking in deepwater turbidite reservoirs. Grain size controls reservoir quality and has causative or correlational effects on most well logs. Additionally, bed thickness affects well logs in various ways because of different vertical logging-tool resolutions. The objective of this paper is to quantitatively classify rock and bed types based on conventional well logs to assist facies interpretation and stratigraphic reservoir modeling.

We model physical properties and well-log responses originating from clastic reservoirs with different grain-size distributions in the context of deepwater turbidite systems. The model accounts for fluid effects introduced by capillary transitions and salty connate water. Petrophysical relationships are examined between grain sizes and pore geometry as inferred from the combined effects of initial connate-water saturation and reservoir capillary pressure. From modeling, we derive several quantitative petrophysical attributes which correlate significantly with grain size. A list of such attributes includes volumetric concentration of shale, total porosity, neutron-density porosity difference, and reservoir quality index (RQI). Rock classification is then performed based on a relevant set of attributes to detect and rank different rock types with specific grain-size distributions. Concomitantly, a quantitative rock classification scheme using three-dimensional Thomas-Stieber diagrams constructed with gamma ray, bulk density, and resistivity logs is used to classify petrophysical zones based on their average bed thicknesses. A dual-attribute rock classification scheme is proposed to better associate rock types with depositional facies.

The above-mentioned rock-classification and bed-typing methods are synthesized and applied to a turbidite field from the Gulf of Mexico. We perform facies analysis based on the vertical succession of rock types (grain sizes) and the inferred variations of bed thickness. The field case demonstrates that these two geologic attributes have great potential in reducing uncertainty and non-uniqueness in the construction of stratigraphic reservoir models. Results indicate that the classified rock types and their petrophysical ranking agree with core data while the interpreted facies fit into the depositional context as inferred from core descriptions and seismic horizons.
A Correlation for the Coefficient of Inertial Resistance for Producing Reservoirs within the Columbus Basin
Authors: Baksh Kirk
Published: June 2014

BP Trinidad and Tobago LLC produces gas from the Columbus Basin located off the east coast of Trinidad. Gas is produced via eleven producing platforms and daily gas production averages 2.3 bscfd. Gas produced is used to supply a domestic market and an LNG scheme. The field portfolio comprises a mix of new to mature producers producing from a deltaic environment which consists of several stacked, good quality sandstone reservoirs. The wells have been primarily designed as big-bore/high-rate completions (equipped with continuous down-hole and surface monitoring) with the aim of delivering gas to market with minimal well count.

Performance data has shown that the non-Darcy rate dependent skin is the biggest contributor to the total skin effect in these high rate wells. Early determination of the non-Darcy flow coefficient "D" enhances the ability to accurately forecast well deliverability; which is critical to both the end users and the business for proper activity planning and capital efficiency. It stands to reason that a proper understanding of same is also advantageous in predicting the performance of new producers.

Predicting the non-Darcy flow coefficient in the absence of well test data requires the value of the coefficient of inertial resistance, β; which is normally determined experimentally. This paper outlines the methodology whereby a correlation for β was developed using non-Darcy flow coefficients obtained via well tests and corrected to sand top; hence making it possible to provide an estimate of the non-Darcy flow coefficient for proposed producers. The predicted performance is then compared against actual performance for a number of cases.
Integrating Completion and Drilling Techniques to Improve & Maximize Production over the Life of the Well
Authors: Scott Gregory , Smith* Lee M. , Johnston Adam D.
Published: June 2014

This paper describes application of an integrated approach that combines drilling and completion techniques in a new use of reaming tools currently used for reaming-while-drilling (RWD) operations, in a way that minimizes the need for SOP of using a dedicated reamer run. The RWD application provides the enhanced wellbore geometry needed to design and engineer solutions using maximum size (OD) conventional casing, liners, expandable casing and multiple swellable packers. This type of assembly for drilling /completion design, currently utilized in multiple Williston Basin wells, ND, is shown to consistently result in shorter drilling time and successful first casing/liner runs. Currently this type of cross functional approach has been used on over 300 wells/ 3,000,000 ft. of lateral.
Eagle Ford Completion Optimization Using Horizontal Log Data
Authors: Slocombe R. , Acock A. , Fisher K. , Viswanathan A. , Chadwick C. , Reischman R. , Wigger E.
Published: June 2014

Schlumberger and four Eagle Ford Shale Play operators drilling in South Texas joined a consortium initiative to acquire various types of open hole logging data in several horizontal wells, and use the data to design the completions with optimum fracture stage and perforation cluster positioning. Horizontal production logs were subsequently used to gauge the effectiveness of using the log data to engineer the completions. This paper outlines the data acquisition techniques, analyses made on that data, application, results and conclusion.

Previous work carried out on production logging data acquired in several shale plays including the Eagle Ford (Miller et al, 2011) shows a significant variation in perforation cluster contribution. Other documented results showing the effect of targeting similarly stressed rock for fracture treatments (Waters, Heinze, Jackson, 2011) in the Marcellus. The objective of this study was to improve the initial flow capacity of the well by increasing the number of perforation clusters contributing to production. A related objective was to determine the optimal horizontal logging program that was needed to characterize the rock with minimal interruption to existing work flows.

This paper will show the results of data acquired over 12 horizontal wells in the Eagle Ford Shale (see map in figure 1). Petrophysical and geomechanical analyses were based on horizontal logging measurements and used as inputs to an engineered completion design tool that generated a recommendation on each well design. The design tool grouped intervals with similar properties for stimulation treatment. Following the treatment, horizontal production logs were run through the zones to measure the perforation cluster contribution.

The results of the study have the potential to change the way Unconventional Resources are developed. Recent trends have seen a shift away from data acquisition to blind geometrical fracturing. This paper examines the value of acquiring petrophysical data in the lateral section and its application to completion optimization, the minimization of wasted resources, and the impact on early production.
Frac Pack Completion Scorecard: The Importance of Scoring High
Authors: Marquez Maricel , Knobles Mark , Norman Wm. David , Oudtshoorn Cobus , Naha Susmito
Published: June 2014

Frac packing is one of the preferred completion techniques for deepwater wells in need of sand control. Frac pack completion performance and reliability can have a significant impact on the economic viability and profitability of a project, particularly for deepwater developments where the cost of intervention and completion failure can be very high. This work discusses key lessons learned and best practices identified from look back studies conducted on frac pack completions in deepwater fields across the world. The frac pack completion scorecard, a tool that provides a normalized means to evaluate the quality of the completion, thus avoiding possible bias based on reservoir parameters or wellbore architecture, focuses on key aspects of the well design and installation process, including rock stresses and well orientation, debris management, perforating, frac design and execution, fluid loss management, and mechanical issues with hardware components. The tool has been validated with data collected from more than 100 wells over a period of eight years, and has proved to be a valuable workflow for root cause analyses to identify probable causes for sand control completion failures, increasing skins and declining productivity index (PI) values over time. It has also been effectively used as a predictive tool for future well performance and to make data-driven, risk-weighted decisions concerning well deliverability thresholds. When the design and installation processes and procedures are shaped around scoring well on the scorecard, the results are better wells not only initially, but for the life of the project.
Effect of Concentration on HPAM Retention in Porous Media
Authors: Zhang Guoyin , Seright R.S.. S.
Published: June 2014

This paper investigates the effect of hydrolyzed polyacrylamide (HPAM) polymer concentration on retention in porous media by use of both static and dynamic measurements. Consistent results by use of these two methods show that different polymer-retention behaviors exist in dilute, semidilute, and concentrated regions. In both the dilute and concentrated regions, polymer retention has little dependence on concentration. In contrast, in the semidilute region, polymer retention is concentration dependent. If a porous medium is first contacted sufficiently with dilute polymer solution to satisfy the retention, no significant additional retention occurs during exposure to higher HPAM concentrations. On the basis of the experimental results, a concentration-related retention mechanism is proposed that considers the orientation of the adsorbed polymer molecules and the interaction between molecular coils in solution. By use of this model, we explain why polymer retention does not show much dependence on concentration in the dilute and concentrated regimes. Further, in the semidilute region, we explain how moderate coil interactions lead to mixed adsorbed-polymer orientation and magnitude on rock surfaces, and retention becomes concentration dependent. In field applications of polymer and chemical floods, reduced polymer retention may be achieved by first injecting a low-concentration polymer bank.
Compositional Modeling of Tight Oil Using Dynamic Nanopore Properties
Authors: Wang Yuhe , Yan Bicheng , Killough John
Published: June 2014

A typical tight oil reservoir such as the Bakken has matrix pore sizes ranging from 10 nm to 50 nm. At such small scales the confined hydrocarbon phase behavior deviates from bulk measurements due to the effect of capillary pressure. In addition, compaction of pore space can bring about order of magnitude changes for tight oil formation properties during pressure depletion further exacerbating these deviations. Without considering these facts a conventional reservoir simulator will likely not be able to explain the inconsistent produced GOR observed in the field compared to simulated results. The effect of these inaccuracies on ultimate recovery estimation can be devastating to the underlying economics.

This paper presents a compositional tight oil simulator that rigorously models pressure dependent nanopore-impacted rock and fluid properties, such as suppression of bubble point pressure, decrease of liquid density, and reduction of oil viscosity as well as their interactions with pore space compaction. The cubic Peng-Robinson equation of state is used for phase behavior calculations. Capillary pressure is evaluated by standard Leverett J-function for porous media. Modifications to the stability test and two-phase split flash calculation algorithms are provided to consider the capillarity effect on vapor-liquid equilibrium.

The simulator can capture the pressure-dependent impact of the nanopore structure on rock and fluid properties. As a result, the problem of inconsistent GOR is resolved and the history matching process is greatly facilitated. It is shown that inclusion of these enhanced physics in the simulation will lead to significant improvements in field operation decision-making and greatly enhance the reliability of recovery predictions.
The Risk of Using Risk Matrices
Authors: Thomas Philip , Bratvold Reidar B. , Eric Bickel J..
Published: June 2014

The risk matrix (RM) is a widely espoused approach to assess and analyze risks in the oil and gas (O&G) industry. RMs have been implemented throughout that industry and are used extensively in risk-management contexts. This is evidenced by numerous SPE papers documenting RMs as the primary risk-management tool. Yet, despite this extensive use, the key question remains to be addressed: Does the use of RMs guide us to make optimal (or even better) risk-management decisions?

We have reviewed 30 SPE papers as well as several risk-management standards that illustrate and discuss the use of RMs in a variety of risk-management contexts, including health, safety, and environment (HSE), financial; and inspection. These papers promote the use of RMs as a “best practice.” Unfortunately, they do not discuss alternative methods or the benefits and detriments of the use of RMs.

The perceived benefit of the RM is its intuitive appeal and simplicity. RMs are supposedly easy to construct, easy to explain, and easy to score. They even might appear authoritative and intellectually rigorous. However, the development of RMs has taken place completely isolated from scientific research in decision making and risk management. This paper discusses and illustrates how RMs produce arbitrary decisions and risk-management actions. These problems cannot be overcome because they are inherent in the structure of RMs. In their place, we recommend that O&G professionals rely on risk- and decision-analytic methods that rest on 250 years of scientific thought and testing.
Estimation of Effective Fracture Volume Using Water Flowback and Production Data for Shale Gas Wells
Authors: Alkouh Ahmad , McKetta Steven , Wattenbarger Robert A.
Published: June 2014

Gas production data may be the main tool used to analyze shale gas reservoirs. Water production is usually not included in the analysis. In this paper, post-frac water flowback and long-term water production are added to the analysis. These water data are usually available but are analyzed separately and not combined with long-term gas production data. In this paper, procedures and examples are presented for including water flowback and water production data in the analysis of shale gas wells using rate transient analysis.

A number of simulation cases were run. Various physical assumptions were used for the saturations and properties that exist in the fracture/matrix system after hydraulic fracturing. Water flowback and long-term production periods were then simulated. The results of these simulations were compared with data from actual wells using diagnostic and specialized plots. These comparisons lead to certain conclusions which describe well/reservoir conditions after hydraulic fracturing and during production.

This paper shows the benefits of a new method for combining water flowback and long-term water production data in shale gas analysis. Water production analysis can provide effective fracture volume which was confirmed by the cumulative produced water. This will help when evaluating fracture-stimulation jobs. It also shows some pitfalls of ignoring flowback data. In some cases the time shift on diagnostic plots changes the apparent flow regime identification of the early gas production data as well as water production data. This leads to different models of the fracture/matrix system. The presented work shows the importance of including water flowback data in the long-term production analysis.
Enhanced Oil Recovery in Gas-Flooded, Carbonate Reservoirs by Wettability-Altering Surfactants
Authors: Wang Leizheng , Mohanty Kishore
Published: June 2014

Gas aided gravity drainage is a common oil recovery technique in anticline-shaped oil reservoirs. If the permeability is low and the reservoir is oil-wet, the remaining oil saturation can be quite high. The goal of this work is to mobilize a part of this oil by surfactant injection. Different coreflood strategies including Gas-Surfactant-Gas (GSG), Gas-Water-Surfactant-Water (GWSW), Gas-Surfactant-Water (GSW), and Gas-Surfactant-Water-Gas (GSWG) floods were investigated. GSG, GWSW and GSWG corefloods conducted in limestone cores recovered about 40-50% of the original oil in place (OOIP) due to the injection of surfactant. GSW corefloods conducted in a vuggy dolomite recovered less, about 20% OOIP incrementally. A 2D conceptual simulation model was built for an anticline reservoir for gas and surfactant solution injection. GSG flooding using wettability altering surfactant exhibited high oil recovery at the field-scale. IFT reduction, wettability alteration, and foam formation contributed to enhanced oil recovery.
Video Production Logging and Polymer Gel Yields Successful Water Isolation in the Fayetteville Shale
Authors: Brady J. , Shattuck D. , Parker M. , Sramek C. , Jones A. , Gould J. , Jayakumar S.
Published: June 2014

Implementation of video production logging in conjunction with the use of high molecular weight polymer gels, has led to successful water isolation operations in the Fayetteville shale. The dry natural gas field, located in northern Arkansas, is a horizontal play with the wells cased, cemented, and completed with multi-stage slickwater fracture stimulations using perforation and plug technology (Harpel, 2012).

Accurate detection of extraneous water entry points along the wellbore is vital for precise water isolation treatment, while still protecting the hydrocarbon producing intervals. Conventional production logging tools have been utilized in the past but proved to be expensive, due to the wellbore configuration, and imprecise because of the horizontal trajectory and debris encountered in the wellbore, with the debris generally rendering the spinner tool inoperable. Video logging tools, deployed in combination with high frequency temperature and pressure gauges, have considerably improved identification of water entries along the wellbore. In addition, the use of a smaller logging assembly has also drastically reduced workover costs by permitting logging through the existing 2-3/8" OD production tubing whereas conventional production logging required the removal of the production tubing due to size limitations. By maintaining this wellbore configuration the flowing conditions remain undisturbed and increase the accuracy of the production log.

Based on video production log results the proper water isolation operation is subsequently selected. While cement squeezes and mechanical isolation tools have been applied successfully in horizontal wells to isolate inflow from water producing perforations, they are limited in their applications due to the wellbore configuration and operational costs. Recently, treatment of water producing perforations with chrome (III) carboxylate acrylamide polymer (CC/AP) gel technology has allowed selective treatment in additional sections of the wellbore. These gel treatments have yielded strong results by isolating water production and increasing gas production by reducing the flowing bottomhole pressure. Evaluation and selection of the appropriate polymer gel is discussed along with design considerations and implementation.
Multiphase Compositional Modeling in Small-Scale Pores of Unconventional Shale Reservoirs
Authors: Alharthy Najeeb S. , Nguyen Thanh N. , Teklu Tadesse W. , Kazemi Hossein , Graves Ramona M.
Published: June 2014

Compositional modeling of hydraulically stimulated naturally fractured liquid-rich shale (LRS) reservoirs is a complex process that is yet to be understood. The flow and multiphase mass transfer in the nano-, meso-, and macro-scale pores, as in Eagle Ford, Woodford and Bakken is of great interest. Understanding the production mechanisms from such reservoirs is crucial in the overall effort to increase the ultimate hydrocarbon production. Thus, we focused on deciphering the physical fundamentals of various recovery mechanisms via reservoir modeling. The starting point was examining the phase behavior issues in unconventional reservoirs. Specifically, we constructed phase diagrams using a new correlation to shift the critical properties of components in the nano and meso-scale pores. The correlation was applied to three recently published Eagle Ford fluid samples. The new phase behavior correlation was used in a dual-permeability compositional model to determine the nature of pore-to-pore flow and, eventually, the hydrocarbon production from wells. In the simulation models we allowed for the phase behavior differences between fracture and matrix and included a multi-level flow hierarchy from matrix (nano, meso, and macropores) to fractures and finally to the well. To make computation accurate we resorted to a series of detailed logarithmic local grid refinement (LS-LGR) in various strategic subdomains in the matrix and fracture.

As a result of this modeling study, we have concluded several reasons why hydrocarbon fluids can move in the shale reservoir nano, meso, and macro-scale pores and why we are able to produce from such low-permeability reservoirs. For instance, favorable phase envelope shift of hydrocarbon mixtures in the nano- and meso-scale pores is one of the contributing factors to economic production in gas-condensate and bubble-point systems. Also noted, when the phase envelope is crossed in gas-condensate systems, a large gas-to-oil volume split in the nano, meso, and macro-pores plays a crucial role in hydrocarbon recovery during depletion. For the bubble-point oil region, the low viscosity of the liquid phase and the delay in gas bubble evolution appears as the main reason for favorable oil production. Furthermore, ‘rubblizing’ the reservoir in the vicinity of hydraulic fractures creates another favorable environment for improved drainage, which is why multi-stage hydraulic fracturing is so critical in successful development of shale reservoirs.
Value of Competency and Value of Competency Assessment
Authors: Nieman Timothy L. , Schuyler John , Ford Brett J..
Published: June 2014

What is the value of a competent engineer? How can we be sure that an engineer is actually qualified? Because the big crew change progresses and because regulators worldwide are beginning to require operators to assure the competency of people working in petroleum operations, these questions are becoming increasingly important. We present an approach to address these questions by looking at the value of competency and competency assurance with probabilistic models.

Valuing competency improvement is a value-of-control (VOC) problem, common in such areas as project risk management and risk-based maintenance. Value-of-information (VOI) problems are similar. We demonstrate how to calculate VOC and VOI with decision trees and Monte Carlo simulation. We selected well design as the example application throughout.

The value of a competency assessment is first demonstrated with a decision-tree VOI analysis. With input judgments that we believe are reasonable, the analysis shows that competency assessments are likely underused.

A more detailed well life-cycle model uses Monte Carlo simulation for the stochastic (i.e., probabilistic) calculations. Here, we illustrate a model of training, a well-design process, and multiple review and execution stages during drilling, completion, and production operations. The model features a competency scale, and VOC is shown by valuing incremental competency improvements and an optional peer review. Another VOI example is competency assessment for a junior engineer.

Similar simulation models can help management optimize decisions involving staffing, type and days of structured training, work-process design, and project-design review stages. In addition to reducing the chance and impact of defective engineering, assessments provide important feedback to the engineer as learner, tools for planning training and development, organizational learning, risk management, construction, and safe operations.

We show that VOI and VOC analyses—long used for exploration decisions—can be applied throughout the information processes used in planning and managing processes.
Characterizing Hydraulic Fracturing With a Tendency-for-Shear-Stimulation Test
Authors: McClure Mark , Horne Roland
Published: June 2014

The classical concept of hydraulic fracturing is that a single, planar, opening mode fracture propagates through the formation. In recent years, there has been a growing consensus that natural fractures play an important role during stimulation in many settings. There is not universal agreement on the mechanisms by which natural fractures affect stimulation, and these mechanisms may vary depending on formation properties. One potentially important mechanism is shear stimulation, in which increased fluid pressure induces slip and permeability enhancement on pre-existing fractures. We propose a tendency-for-shear-stimulation (TSS) test as a direct, relatively unambiguous method for determining the degree to which shear stimulation contributes to stimulation in a formation. In a TSS test, fluid injection is performed while maintaining the bottomhole fluid pressure slightly less than the minimum principal stress. Under these conditions, shear stimulation is the only possible mechanism for permeability enhancement (except, perhaps, thermally induced tensile fracturing). A TSS test is different from a conventional procedure because injection is performed at a specified pressure (rather than a specified rate). With injection at a specified rate, fluid pressure may exceed the minimum principal stress, and it may cause tensile fractures to propagate through the formation. If this occurs, it will be ambiguous whether stimulation was because of shear stimulation or tensile fracturing. Maintaining pressure less than the minimum principal stress ensures that the effect of shear stimulation can be isolated. Low-rate injectivity tests could be performed before and after the TSS test to estimate formation permeability. An increase in formation permeability would indicate that shear stimulation has occurred. The flow-rate transient during injection may also be interpreted to identify shear stimulation. Numerical simulations of shear stimulation were performed with a discrete-fracture-network (DFN) simulator that couples fluid flow with the stresses induced by fracture deformation. These simulations were used to qualitatively investigate how shear stimulation and fracture connectivity affect the results of a TSS test. Two specific field projects are discussed as examples of a TSS test, the Enhanced Geothermal Systems (EGS) projects at Desert Peak, Nevada, and Soultz-sous-Forêts, France.
Offshore Field Application of a Low Corrosive Fluid Designed for De-Scaling of Well with ESP Completion
Authors: Bakar H. B. , XianLung I. C. , Nadzri M. Z. , Zaini M. A. , Jaafar J. B. , Hirman M. , Nasr-El-Din H. A. , de Wol C. A.
Published: June 2014

The applications of both inorganic and organic acids are to dissolve scales, remove filter cakes and increase the permeability of carbonate and sandstone formations, during processes like de-scaling, completion and stimulation. Often in sandstone mineral acid treatments have hidden costs from logistics, handling and failure to meet performance targets.

The use of a novel low corrosive chelating agent, glutamic acid N, N-diacetic acid (GLDA), instead of hydrochloric acid, was evaluated to remove calcium carbonate and iron scale depositions found in Well A's downhole electrical submersible pump system and near wellbore area at elevated temperatures and pressures. Besides scaling issues, high H2S concentration, up to 300ppm, were also detected in this well.

Extensive lab studies were conducted to determine the chemical's compatibility with the ESP components, dissolution effectiveness of the collected downhole samples and corrosion properties on carbon steel tubulars in the presence of hydrogen sulphide gas. The results proved that the chemical was able to dissolve more than 95% of calcite and iron scales without damaging the cables and elastomers of the ESP after 24 hrs soaking at reservoir temperature.

The offshore treatment application did not require chemical specialist on-board or additional additives such as corrosion inhibitors, intensifiers, iron control agents, etc. Nor did it require a large footprint to place the chemical on the platform. The chemical was bullheaded easily through annulus and tubing without having to pull out the pump. The cost savings of this rigless intervention is estimated to be USD 2mil. The success of this treatment was realized by additional gain of 112 bopd and the H2S concentration was reduced to 10 ppm.

The field application data, along with the lab data, confirms that the GLDA based solution is an effective de-scaling and stimulation fluid that is gentle to various types of well completions, safe to handle, and cost effective to use. This paper highlights the successful use of the GLDA in contributing to the much improved well productivity focusing on the lab studies, operational considerations and production performances of Well A.
Mass Transfer on Multiphase Transitions in Low-Temperature Carbon-Dioxide Floods
Authors: Okuno R.. , Xu Z..
Published: June 2014

Mixtures of reservoir oil and carbon dioxide (CO2) can exhibit complex multiphase behavior at temperatures typically less than 120°F, in which a third CO2-rich liquid (L2) phase can coexist with the oleic (L1) and gaseous (V) phases. The three-phase behavior is bounded by two types of critical endpoints (CEPs) in composition space. The lower CEP (LCEP) is a tie line in which the two liquid phases merge in the presence of the V phase, and the upper CEP (UCEP) is a tie line in which the L2 and V phases merge in the presence of the L1 phase. Slimtube tests reported in the literature show that low-temperature oil displacement by CO2 can result in the high displacement efficiency of more than 90% when three phases are present during the displacement. The nearly piston-like displacements can be quantitatively reproduced in numerical simulations when the CEP behavior is properly considered. However, it is uncertain how multicontact miscibility (MCM) is developed through the interaction of flow and three-hydrocarbon-phase behavior.

This research presents a detailed analysis of mass conservation on multiphase transitions between two and three phases for the limiting three-phase flow, where the L1 phase is completely displaced by the L2 phase on the LCEP. The analysis indicates that interphase mass transfer on multiphase transitions occurs in the most-efficient way for MCM development. Simple analytical conditions derived for MCM through three phases are applied to 1D fine-scale simulations of CO2 floods by use of four and more components. Results show that the MCM conditions are nearly satisfied when the effect of numerical dispersion is small. MCM is likely developed through three hydrocarbon phases on the LCEP in the cases studied. This is consistent with analytical solutions of water and gas injection presented in the literature, in which MCM is developed on a CEP for the aqueous, V, and L1 phases. For MCM cases in this research, the L2-V two phases are present upstream of the miscible front if the composition path does not go through the UCEP tie line. However, they also can be miscible on the non-L1 edge of the UCEP tie line if the MCM composition path goes through it.

Three-phase flow gradually changes to two-phase flow with varying pressure in the presence of numerical dispersion. It is shown that interphase mass transfer on multiphase transitions becomes less efficient during the change until the three-phase region completely disappears.
Gas Condensate Well Unloading Critical Rate
Authors: Alamu Mhunir Bayonle
Published: June 2014

Profile of critical rate for 106 vertical wells producing from high pressure formations has been used to determine an unloading critical rate for well producing gas and condensate. The evaluation involved loaded, questionable and unloaded wells. When this data was compared with experimental data obtained from flow loop where liquid loading condition was investigated, it was observed that any gas condensate well producing above a critical rate of 12 MMSCF/D will produce in an unloading manner.

OLGA, a 3-phase transient multiphase flow simulator was used to confirm the conclusion of well test result. Four gas condensate wells were investigated out of 106 well tested at field conditions - one unloaded; one questionable and two loaded. Results of the simulation confirmed the ‘unloaded’ well was actually producing freely in a stable manner at the wellhead. The ‘questionable’ well was found to be to be producing in churn flow regime characterized by certain degree of instability. The two ‘loaded wells’, on the other hand, were found to be producing but characterized with mild and severe flow instability at the wellhead. A loaded well simulated with 12 MMSCF/D production rate produced in a stable manner.

Three of the wells selected for study had production tubing depth greater than 10,000ft. to study effect of flow development length on liquid loading behaviour of gas condensate well. A modified Froude number based on production tubing depth and entrained liquid fraction in the gas stream showed that a gas condensate is most likely to be loaded if operated below a value of 1000.