bluuebunny/crossref_metadata_2025 huggingface dataset:
Constraining the Complexity of Stimulated Reservoir Volume during Multi-Stage Hydraulic Fracturing of Horizontal Wells through Inter-Well Pressure Hit Modeling
Authors: Shokri A. Rangriz , Chalaturnyk R. J. , Bearinger D. , Virues C. , Lehmann J.
Published: October 2017

To determine the degree of connectivity and complexity of a stimulated fracture network, a prescriptive completion program was undertaken in the Horn River Shale Basin which enabled continuous monitoring of pressure interactions among horizontal wells during multi-stage hydraulic fracturing. This paper introduces a novel approach to characterize the stimulated fracture network, and consequently, to optimize the stimulation, wellbore placement, and re-fracturing designs, by integrating the pressure hits captured from passive wellbores on a pad during fracturing operations. If effective, it may also provide a cost-effective alternative to microseismic monitoring.

The workflow initially considers a rigorous data analysis on available pressure hits at each frac-stage in time and space, including the location of pressure events, time of flights to offsetting stimulation, and the magnitude and intensity of pressure hits/falloffs. Streamline simulation, assisted with a hydraulic fracturing module, is then used to match the pressure hits/falloffs in the passive wells. This ultimately provides a dynamic probabilistic 3D map of the fracture network growth, reservoir complexity and inter-well connectivity. The fundamental mechanisms of hydraulic fracturing and the interactions across natural and induced fractures (fracture initiation/propagation/growth) are implemented by means of an advanced coupled hydro-mechanical code, based on distinct element method.

Results from initial data analyses were fed into a hydro-mechanical model, which incorporated the physics of the hydraulic fracturing process, in order to reproduce the pressure hit signatures. An assisted streamline-based technique was used to simulate various scenarios of pressure hit responses to construct a database of standard pressure hit/falloff patterns. This database, compiled into a dynamic 3D map, facilitated a probabilistic approach to calculate a robust estimate range of stimulated fracture network of the pad area. This database can be subsequently used in future stimulation and re-fracturing designs. The backbone of the highly complex fracture network, extracted from pressure hit/falloff data, was found to closely align with high-resolution microseismic data.

Calibration of the hydro-mechanical model using the pressure hit data provides increased confidence in the use of the model to optimize well placement and hydraulic fracturing designs. In the absence of microseismic data, this unique workflow has the potential to deliver real-time on-site monitoring of fracturing operation at a reduced cost and acceptable accuracy, to provide additional statistics on complexity of stimulated reservoir volume, and to offer a better assessment of the likely range of the induced fracture network among horizontal wells.
New Model for DFIT Fracture Injection and Falloff Pressure Match
Authors: Liu G. , Ehlig-Economides C.
Published: October 2017

Analysts regard the fracture injection and falloff test known as the diagnostic fracture injection test (DFIT) as a reliable tool to quantify formation closure stress, leakoff coefficient, formation permeability, and pressure. The recent analytical DFIT model for before and after closure enables matching the pressure falloff for abnormal leakoff behaviors, and quantification of many more formation parameters than traditional DFIT models. However, the model design addressed only the falloff data after shut-in, and many express concerns that net pressure implied by the falloff is inconsistent with the injection pressure behavior. This paper provides a model capable of matching both injection and falloff pressure behavior.

The pressure falloff model is capable of quantifying essential pressure values including, in order of occurrence, instantaneous shut-in pressure (ISIP), minimum fracture propagation pressure, one or more closure stress values, minimum stress, and pore pressure. The early pressure response represents the dissipation of three kinds of friction, wellbore, perforation, and near-wellbore friction, each of which are quantified, and which together comprise the difference between the pressure at the end of injection and the ISIP. Presence of tip extension enables quantification of the minimum fracture propagation pressure. The minimum stress is consistent with the final closure stress. Subtracting the closure pressure and friction pressure losses from the recorded or calculated bottomhole pressure provides the fracture net pressure. The model match for injection pressure behavior incorporates the same pressures and consistent values for 2D fracture geometry and leakoff coefficient.

The global match confirms not only the estimation of formation and fracture properties from the pressure falloff analysis, but also the pressure distribution along the wellbore, through the perforations and the near wellbore, and in the fracture during and after injection. In particular, by matching both injection and falloff, the model incorporates friction pressure losses that can explain apparent excessive net pressure.

The match with both injection and falloff pressure variation addresses concerns that the net pressure implied by the falloff model match cannot be consistent with observed injection behavior. When the pressure difference between the final DFIT pick for closure stress and the pressure at the end of injection is very large, the reason may be large friction pressure losses and/or tip extension. Design for the main fracture treatments could consider an altered perforation strategy to reduce friction losses and/or reduce cluster spacing to address very low effective permeability likely consistent with tip extension and confirmed by the after closure match.
Frac Hit Induced Production Losses: Evaluating Root Causes, Damage Location, Possible Prevention Methods and Success of Remedial Treatments
Authors: King George E. , Rainbolt Michael F. , Swanson Cory
Published: October 2017

Frac hits or "frac bashing" is a fracture-initiated well-to-well communication event that can create production losses (or gains), and on occasion, mechanical damage when frac energy from a stimulated well extends into the drainage area or directly contacts an adjacent or offset well. Pressure increases have been detected in wells at distances ranging from hundreds to thousands of feet from the stimulated well. While these in-zone frac hit events do not pose an environmental problem if there is no failure of containment, there can be some alteration of the production potential in one or both of the wells involved.

Frac hits along the preferential fracture plane were an uncommon but known event when the completion method only involved vertical wells, but the rate of incidence has increased sharply as the preferred completion method has shifted to relatively closely-spaced, multiple fractured horizontal wells (MFHW) in low permeability formations such as the mudstone rocks commonly referred to as shales.

Mechanical damage within the well and success of methods of prevention, damage control and remediation will be examined by case histories and published contexts of incidents in several basins, but will not be the main goal of the paper.

The primary effort will focus on examining causes of production loss and duration of the loss, including looking at production declines pre-hit and post-hit. Known causes include in-situ stress alteration potential, timing of fracture closure, near-wellbore proppant loss, liquid loading, rock-fluid interactions, sludges and wetting factors. Also considered will be geological effects such as regional fractures and linked natural fracture clusters. A main objective will be to identify pressure transient, chemical analysis or other monitoring techniques to identify location and type of damage.

Remedial operations are most effective when the potential cause of production losses can be ranked probabilistically and the depth of the production-reducing event can be estimated as near-field or far-field. Analyzing this data will also assist in defining whether chemical or mechanical treatments such as refracturing or a hybrid treatment system may be the best approach.
Horizontal Water Injection to Sustain Production in a Low Oil Price Environment
Authors: Pettengell Katherine , Hascakir Berna
Published: October 2017

Over the past year and a half, the price of oil has plummeted from over $100 US per bbl in early 2014 to less than $47 US per bbl in the mid of 2017. In an attempt to sustain production without incurring significant additional expenditures, some operators may choose to implement enhanced oil recovery projects (such as waterflooding) while also utilizing existing infrastructure in the field. This paper focuses on one method of doing this by converting watered out or poor-performing horizontal production wells into horizontal water injection wells. The goal of this study was to create a screening criteria list which will enable assessment of a field to see if it could benefit from horizontal injection by way of converted horizontal production wells.

The study began with a literature search to determine if a similar study had been conducted previously. When the study was found to be unique, the literature search then focused on understanding the background of horizontal water injection, along with case studies to see which conditions led to success or poor performance of horizontal water injection schemes. The applications, optimization techniques, evaluation methods and challenges involved in conversion of horizontal production wells to injectors and the horizontal injection process itself have been summarized and compiled into a screening criteria chart which can be broadly applied to any field to see if it is suitable for the proposed application. The screening process works by assigning zero, one, or two points to the response to a number of criteria regarding the reservoir, fluids, wells, and other information. A higher point value indicates a higher likelihood of a positive outcome if a horizontal production well is converted to a water injector.
Emerging Leaders Alliance - The Application of Salient Learnings In Corporate Organizations
Authors: Pradhan Y. , Sturrock A. , Kotenev M. , Nunoo N.
Published: October 2017

The Society of Petroleum Engineers has actively participated in the Emerging Leaders Alliance (ELA) for 9 years since its inception in 2008. Through a stipend obtained from the SPE International Young Member Programs Budget, 86 young members have had the opportunity to attend the multiple day ELA. Attendees of the ELA are primarily early career leaders with management potential from the nine partner societies. Though topics stay relevant through a continuous improvement process, this paper will specifically address three topics from the 2016 ELA which were deemed most relevant to the authors: Performance Management, Emotional Quotient (EQ), and Technical to Managerial Transitions. The paper will discuss the significance, development and proposed protocol of performance management, whether if professionals are in the conducting or receiving end. The paper will also cover the roles of emotional quotient, or EQ, across technical and managerial positions for professionals of all levels of experience. Finally, the paper will cover when industry professionals should consider the transition from technical to management if they are interested. Interviewees included in the paper discuss how prioritizing these topics set themselves for successful careers. The interviewees will span a wide range of experience levels to display the relevance and application of the chosen topics despite one's career path. Young professionals should consider the three topics emphasized in the paper, as these are commonly overlooked or not prioritized. Proactiveness as early as possible on the topics discussed in this paper could increase professionals' chances of having a successful career. Professionals should also recognize that leaders and whom they supervise hold equal accountability to make the applications of performance management, emotional quotient and the technical to management transition conducive to the workplace.
Electronic Sliding Sleeve for Unlimited Zone Multistage Completion System
Authors: Merron Matt , Walton Zachary , Fripp Michael
Published: October 2017

A new electronic sliding sleeve was developed for hydraulic fracturing that combines the best features of traditional sliding sleeves and plug-and-perf techniques. The electronic sliding sleeve combines the operational efficiency of sliding sleeves with the potential to perforate unlimited zones inherent to plug-and-perf operations. This tool helps improve the efficiency of multistage fracturing sleeve completions by enabling more zones to be perforated and therefore more of the formation to be fractured.

Traditional sliding sleeves use a series of progressivelysized fracturing balls that shift sleeves along with progressivelysized baffles. The number of zones is limited by the strength of the fracturing ball and the interference between the ball and the baffle. Traditional sliding sleeves, however, offer an operational efficiency advantage compared to traditional plug-and-perf fracturing techniques. The electronic sliding sleeve is of monobore construction, which helps eliminate pumping restrictions through a series of progressivelysized baffles. An electronic sliding sleeve helps eliminate the mechanical complexity of other monobore fracturing tools and enables access to an unlimited number of zones.

The electronic sliding sleeve operates by counting the passage of fracturing balls through the tool and then shifting the sleeve when the programmed number of balls has passed. The electronic sliding sleeve has an on-board sensor and processor equipped to count the fracturing balls. Once the programmed number of fracturing balls has been detected, an actuator releases stored energy to enable the sleeve to shift. The key to the electronic sliding sleeve is a newly developed electrohydraulic lock, which stores the actuation energy. The electronic assembly increases the reliability of the sliding sleeve because the key components of the tool are embedded within the casing string and are not subject to proppant erosion or becoming caught on proppant trapped within mechanical parts. The electronic sliding sleeves can be used in the stimulation of vertical, horizontal, and extended reach wellbores.

A newly developed electronic sliding sleeve presents a new method for performing multistage hydraulic fracturing and is especially applicable in extended reach applications by offering an unlimited number of zones with a simple monobore construction. The programmable electronics help enable increased flexibility, reliability, mechanical simplicity, and robustness.
API RP 67 Recommended Practice for Oilfield Explosives Safety: Development of Proposed Changes to the Third Edition
Authors: Ayre David , Barker James
Published: October 2017

API RP 67 (1994) provided the industry with a common set of explosive safe practices. The last significant update was the second edition (API RP 67 2007). Since that time, the industry has undergone major advances in conveyance methods, technology, and processes. Additionally, in the post-9/11 era, security has been and is still being increased.

During the last five years, a dedicated group of more than 120 industry professionals has attempted to update and improve the recommended practice (RP) to enhancesafety for all individuals involved with oilfield explosive materials. Industry dialog has been fostered through discussions during perforating safety forums and industry safety and technology tradeshows.

The proposed new changes for the third edition of API RP 67 include the following:

Segregation of initiators into safety categories. Consideration of slickline, tractor, and coil tubing conveyance methods, in addition to the standard electric line (e-line) and tubing conveyed perforating (TCP) conveyance methods. Thermal management of explosives, particularly with consideration of HMX temperature overexposure and thermal runaway events. Safer use of pressure equipment with explosives. Improved security, audits, and personnel training. A fuller review of wellsite hazards associated with perforating.

At the time of this writing, the third edition is in the final stages of review, with publication expected in late 2017. This paper discusses these proposed changes and the reasoning for their inclusion in the third revision of API RP 67.
Multicolor Fluorescent Silica Nanoparticles as Tracers for Production and Well Monitoring
Authors: Murugesan Sankaran , Suresh Radhika , Kuznetsov Oleksandr , Khabashesku Valery N. , Darugar Qusai
Published: October 2017

Tracers play an important role in the oil and gas industry by providing valuable information about reservoirs. In particular, tracers can help in mapping water movementfor determining information on water flooding that can be used to improve hydrocarbon recovery efforts. Some of the challenges associated with current chemical or dye-based tracer technology are thermal degradation over time, phase separation, and tedious detection processes. To overcome these drawbacks environmentally friendly, multicolor silica nanoparticles as tracershavebeen proposed toprovide simpler and faster detection through fluorescence spectroscopy.
Designing Low-ECD Drilling Fluids for Superior Hydraulics and Sag Performance: A Rheological Approach
Authors: Kulkarni Sandeep D. , Williams Robert , Livanec Philip W. , Jamison Dale E. , Kohlt Timo F.
Published: October 2017

Typical organophilic clay-free invert-emulsion fluids (IEFs) are known to offer improved performance compared to conventional organophilic clay-based IEFs. However, for both the typical clay-free IEFs and conventional clay-based IEFs, high-temperature stability continues to remain a challenge from aequivalent circulating density (ECD) management and cuttings transport standpoint. This paper discusses the latest generation of clay-free IEFs, termed as "low-ECD clay-free IEFs,"that consist of specific combinations of weighting agents, colloidal particles, and polymers. The composition of these low-ECD fluids leads to different rheological behavior compared to typical clay-free IEFs, especially at high temperatures (>200°F). This paper demonstrates that the peculiar rheological behavior of the low-ECD clay-free IEFs results in superior hydraulics and sag performance. Understanding the rheology also helps effectively design these fluids.

Experiments were conducted to study the rheology of several low-ECD and typical clay-free IEFs at high-pressure/high-temperature (HP/HT) conditions using rotational viscometers. Fluids were studied across a temperature range of 40 to350°F and up to 12,000-psi pressure. The data were used to develop models for predicting the rheology of various fluids as a function of temperature and pressure. Using the rheological models, hydraulics performance of the low-ECD and typical clay-free IEFs was simulated in a high-temperature well. The simulations evaluatedthe ECD and cuttings carrying capacity of these fluids. Sag behavior of the fluids in the well was also investigated.

The rheological study showed that typical clay-free IEFs thin with temperature (i.e., viscosity decreases with increasing temperature). In contrast, the low-ECD clay-free IEFs showed increased viscosity with temperature (i.e., temperature thickening). Temperature thickening was especially prominent at lower viscometer rotational speeds (i.e., lower shear rates). The temperature thickening helps the fluid retain its ability to suspend cuttings, barite, and other particulates. The contrast in the rheology behavior was used to demonstrate the ultimate advantage of the low-ECD clay-free IEFs—the desired cuttings transport and sag performance in a well can be achieved at significantly lower wellbore pressures (or lower ECDs) compared to typical fluids. Wellbore case studies confirmed the accuracy of the rheology and hydraulics models for low-ECD fluids and the fluids’ superior performance at high temperatures. The low-ECD clay-free IEFs can be accurately designed to provide superior wellbore pressure management and wellbore stability. This work is crucial for narrow-margin and high-temperature wells.
Improving ASP Performance in Carbonate Reservoir Rocks Using Hybrid-Alkali
Authors: Al-Murayri Mohammed Taha , Kamal Dawoud Suliman , Suniga Pearson , Fortenberry Robert , Britton Chris , Pope Gary A. , Liyanage Pathma Jith , Jang Sung Hyun , Upamali Karasinghe A.N.
Published: October 2017

Waterflood oil recovery in many carbonate oil reservoirs is low due to both high residual oil saturations and low sweep efficiency because of high heterogeneity. An example is the Sabriyah Mauddud reservoir in Kuwait. Alkaline-surfactant polymer flooding (ASP) has great potential for enhanced oil recovery both because ASP flooding reduces residual oil saturation and because of the polymer improves sweep efficiency. Unfortunately, the initial ASP coreflood experiments using conventional alkali showed unacceptably high surfactant retention in the reservoir cores. Several approaches to reducing surfactant retention were tested. Numerous strategies such as the use of chelating agents, sacrificial agents and chemical gradients were tested to reduce retention. The most effective strategy used a hybrid-alkali (NaOH + Na2CO3) in addition to a hydrophilic polymer drive containing a novel co-solvent. In this approach injection pH was increased to 12.5, compared to 10.5 using only Na2CO3. Such high pH is undesirable in sandstones because of reactions with silica minerals, but theexperimental results described here suggest the process is suitable for carbonate reservoirs. With this approach, both low surfactant retention and high oil recovery were achieved in very tight reservoir cores (8-35 mD). This novel approach was validated in a live oil coreflood using preserved cores to represent the reservoir material in the most rigorous way possible. This significant decrease in surfactant retention makes ASP flooding in the Sabriyah Mauddud reservoir viable.
Successfully Completing and Producing a Deepwater Gulf of Mexico Well With No Cement Behind Pipe
Authors: Hopper Tim S. , McCutcheon Joseph B. , Shaposhnikov Pavel
Published: October 2017

Noble Energy, Inc. successfully drilled a deepwater exploration Middle Miocene well in November 2012 and discovered the Big Bend Field, located in the Gulf of Mexico Mississippi Canyon Block 698. As the production liner was being run in the MC 698 No. 1 discovery well, tight hole conditions were encountered near total depth. While pumping the primary cement job, lost returns were observed. Prior to the drilling rig leaving location, a cement bond log was run to evaluate the primary cement job. There was no evidence of cement bond across the main oil-bearing zone or directly above it. This was a concern since there are water sands above the main oil-bearing zone which could compromise future production with behind pipe communication issues, in addition to potentially complicating the completion. Plans were made to pump squeeze cement to remediate the primary cement job. When the rig returned to complete the well, a second cement bond log was run February 2014 and compared to the original cement bond log. The second cement bond log showed a zone of sufficient bonding above the main oil-bearing zone, where no bonding was evident on the previous bond log. There was still no evidence of cement across the main oil-bearing sand. Even though preparations were made to remedial squeeze the primary cement job, the decision was made to not engage in remedial cement operations and to continue with the completion. This paper compares the two cement bond logs and discusses the operational considerations leading to the successful completion of the well and producing a prolific oil well safely with no water production.
Applying Data Management and Visualization to OPEX Reduction and Improved Asset Integrity Programs
Authors: Arciero B. V. , Ismail H.
Published: October 2017

The Digital Oil Field (DOF) has been exhaustively discussed for production enhancement and optimization, but there has been little focus on its use in other areas. This paper describes an integrated approach by multiple business units on how data management and visualization is been applied to enhance decision making, improve cost control, and increase asset integrity in Murphy’s onshore and offshore developments.

Data visualization and the automation of data reporting play an important role in achieving the goal of reducing OPEX and optimizing field operation activities. As more data becomes available, a tool for maximizing the benefits of how data is presented and used in day-to-day decision making is required. This begins with reducing man-hours associated with data acquisition, report-generation, analytical tool development and key performance indicator (KPI) tracking. A data management and visualization tool is currently in-use to enhance offshore operations in chemical management, cost-tracking, and production forecasting, as well as unconventional onshore operations for asset integrity monitoring systems.

Since implementation, the program minimizes duplicate work by field personnel, as well as ensures they are engaged and involved in OPEX reduction and increasing field uptime. Effective visualization of data streamlines decision-making on chemical performance, cost-benefit analysis, and effective treatment. It also maximizes the amount of data available for use and interpretation.

In remote areas onshore field data is entered via mobile devices, providing a fast, simple, and effective tool for managing onshore maintenance campaigns, pigging programs, cathodic protection, & vessel inspections. New workflows provide real-time data and metrics to help make on the fly ‘fit-for-purpose’ decisions. Utilization of apps and dashboards has drastically changed the performance of the asset integrity & maintenance programs and significantly reduced OPEX across onshore and offshore assets, and improves reliability across pipeline and gathering systems by identifying high-risk areas and reducing system upsets.

This shift has moved focus from effective data collection to using the existing data in an efficient and cost-effective way in helping the operations engineering team and field operations in data analysis, KPI-tracking and achieving production and OPEX targets. It also provides indication of existing data gaps and identifies where more data collection would add value to business decisions.
Creating Value by Implementing an Integrated Production Surveillance and Optimization System – An Operator's Perspective
Authors: Sankaran Sathish , Wright David , Gamblin Huan , Kumar Dhilip
Published: October 2017

As operations extend to deeper and more complex reservoirs, the industry is faced with challenges towards efficiently appraising and developing these fields. Some of the key operational challenges include predicting, identifying and mitigating reservoir and well performance issues under uncertainty. Exacerbating this is the issue of volatile oil prices, manpower, staff rotations, increasing volumes of telemetry data handled by asset personnel and complex designs. Engineers often respond to this challenge by reacting to the situation and developing personal tools (spreadsheets) that are often not scalable at the corporate level.

Further, the classical silos of analytical tools are not always able to characterize and pinpoint the cause of any performance degradation. In these situations, there is a need to get a holistic understanding of the well and reservoir behavior by employing various engineering tools and develop effective remediation strategies. This understanding and early remediation leads to maximizing the value of the asset investments through better and prompt decision-making and collaboration.

This paper describes some of the technical challenges faced in deepwater operations and the methodology adopted for implementing an integrated production surveillance and optimization (IPSO) system to mitigate the risks. The IPSO (deepwater digital oilfield) system is designed to be a culmination of emerging information and communications technologies, intelligent algorithms and fit-for-purpose asset management workflows. Case studies are presented highlighting the benefits from implementing the IPSO system across all deepwater assets, including improved well and facility uptime resulting in increased efficiency and reliability, automating data gathering, early understanding of reservoir behavior and better overall performance. In addition, best practices and lessons learned from this deployment in a green field environment were applied to other mature brown field operations within the company.
Density Changes and Reservoir Compaction from In-situ Calibrated 4D Gravity and Subsidence Measured at the Seafloor
Authors: Agersborg R. , Hille L. T. , Lien M. , Lindgård J. E. , Ruiz H. , Vatshelle M.
Published: October 2017

Managing offshore hydrocarbon fields involves costly investments like drilling infill wells or installing compression facilities. A good understanding of the dynamical behavior of the reservoir is required for derisking such decisions. Time-lapse seismic is a suitable monitoring technology, but it involves large operational costs. On the Norwegian continental shelf (NCS), another geophysical method has been in use for two decades: 4D gravity and subsidence surveys, with a cost typically 15% of that of seismic surveys. Field cases show that, in some cases, this technology provides information beyond the reach of seismic within the required timeliness.

Time-lapse gravity changes at the seafloor are sensitive to changes in mass within the reservoir. As an example, vertical movements of water-gas contacts smaller than a meter can be detected under some circumstances by studying this observable (Ruiz et al., 2015). That is possible because of the high accuracy of the time-lapse gravity measurements, which is at the level of a few μGal.

Seafloor subsidence monitoring uses water pressure measurements at the seafloor as a starting point. Once the required tide corrections are applied, the method reaches accuracies of down to 2 mm, depending on the field conditions. This is much better than the accuracy specified by pressure sensor manufacturers, which amounts to typically 10 cm of water for a sensor qualified for 1000 m of water (Ruiz et al., 2016b).
New Method to Reduce Residual Oil Saturation by Polymer Flooding
Authors: Erincik Mehmet Z. , Qi Pengpeng , Balhoff Matthew T. , Pope Gary A.
Published: October 2017

Six coreflood experiments were conducted to investigate the effect of hydrolyzed polyacrylamide (HPAM) polymer solutions on the residual oil saturation in Bentheimer sandstone cores. All six cores were first saturated with brine and then flooded in the following sequence: oil to zero water cut, brine to zero oil cut, glycerin solution to zero oil cut, polymer in low-salinity brine to zero oil cut and finally polymer in high-salinity brine to zero oil cut. The first polymer solution had about the same viscosity as the glycerin solution. The first polymer flood was designed to maximize the effect of viscoelasticity on the residual oil saturation by flooding the cores at a high Deborah number, and as expected resulted in a lower residual oil saturation. The second polymer flood in high-salinity brine had about the same viscosity, but a much lower relaxation time and the flood had a much lower Deborah number. Unexpectedly, there was a further substantial reduction in residual oil saturation during the second polymer flood. The lowest residual oil saturation after the second polymer flood was only 0.07. This is a truly remarkable result considering there was no reduction in interfacial tension, the capillary numbers were maintained below the critical capillary number for Bentheimer sandstone, and the viscosities of both polymer solutions were equal to or less than the glycerin solution.
A Study of Connectivity and Baffles in a Deepwater Gulf of Mexico Reservoir Linking Downhole Fluid Analysis and Geophysics
Authors: Chen Li , Forsythe Jerimiah C. , Wilkinson Tim , Winkelman Ben , Meyer John , Canas Jesus A. , Xu Weixin , Zuo Julian Y. , Betancourt Soraya S. , Shan Dan , Hayden Ron S. , Gendur Jason , Hearn Richard , Kumar Anish , Lake Patrick , Mullins Oliver C.
Published: October 2017

Reservoir architecture and the size and reservoir quality of producing bodies remain a central concern particularly in deepwater. In this case study, high-quality seismic imaging delineated the sand bodies and an intervening shale break between two stacked sands. Wireline evaluation in each well consisted of advanced DFA (Downhole Fluid Analysis), formation sampling and pressure measurements, borehole imaging and petrophysics. Reservoir fluid geodynamic analysis of Wireline asphaltene gradient measurements indicate that each sand body is laterally connected and that the shale break could be a baffle. Geodynamic analysis of reservoir architecture employing seismic analysis and wellbore imaging and petrophysical logging concludes the same. All other PVT and geochemical data are compatible with this assessment; nevertheless, the DFA-measured asphaltene gradients are shown to be superior to all other fluid measurements to determine reservoir architecture. The concurrence of high-resolution seismic imaging with advanced wireline for both formation and reservoir fluid geodynamics enables building robust geologic models populated with the accurate fluid structures of the reservoir. History matching months of production match most probable reservoir realizations which are now the basis of reservoir simulation. Future exploration with step-out wells are being optimized with this powerful workflow.
Proposed Refracturing Methodology in the Haynesville Shale
Authors: Xu Tao , Lindsay Garrett , Baihly Jason , Ejofodomi Efe , Malpani Raj , Shan Dan
Published: October 2017

During the downturn in the oil and gas industry, many operators have chosen to refracture their previously underperforming wells to boost economics with lower investment compared to drilling new wells. More than 100 horizontal wells have been refractured using chemical diverters across multiple basins in North America since the second half of 2013. Many papers have been published discussing these case studies. However, the refracturing results have been inconsistent. One of the biggest challenges of refracturing with chemical diverters is not knowing what is actually happening down hole. To better understand what is happening, more refracture modeling should be performed to more reliably predict production results before spending the upfront capital for a refracturing treatment.

A proposed refracture numerical simulation methodology was employed to take into account the historical production depletion using calculated pressure and stress measurements along the lateral and in the reservoir. The altered stress fields resulting from reservoir depletion are calculated through a comprehensive workflow coupling simulated 3D reservoir pressure with a geomechanical finite-element model (FEM) described in a previous published paper. After the stress and pressure are updated, the new approach outlined in this paper is validated by production history matching real data from a previously refractured well in the Haynesville basin to provide more confidence in the end results. The main uncertainty in the process is how much of the lateral was stimulated. This paper also provides a sensitivity example to show how the model can be altered to predict different lateral coverage percentages.

Refracture modeling still poses a major challenge for engineers because of the reservoir complexity and uncertainty downhole while refracturing (i.e. reservoir heterogeneity, isolation efficiency, etc.). However, this proposed refracturing approach provides a basic guideline on how to model refracturing treatments in a numerical simulator with the help of altered stress fields caused by reservoir depletion. This can be used to better understand why previously refractured wells perform the way they do and to better predict the performance of future refractured wells.
Evolving Completion Technologies Mitigate Proppant Flowback
Authors: Swain C. , Powell J. , Stadnyk S.
Published: October 2017

The concept of "cutting costs at any cost" leads to poor short-term focused decisions which can result in higher total costs in the future. In many instances, any dollars saved in the initial completion are more than offset by costs incurred later in the life of the well. One such example is the operational difficulty and costs incurred in dealing with proppant flowback after fracturing operations are completed. In many such cases, a post-fracture cleanout is required before turning the well over to production, and subsequent additional cleanouts can be required after three to six months of production. This paper will examine the application of a completion methodology which has proven to minimize the inflow of proppant during both the fracture treatment, and during subsequent production. With minimal additional costs associated with the use of the method, the savings result in a benefit to profitability and capital preservation.
Investigating the Performance of Paraffin Inhibitors under Different Operating Conditions
Authors: Dubey Anshul , Chi Yuandao , Daraboina Nagu
Published: October 2017

Mitigating paraffin deposition in production lines has remained a critical issue for the oil industry to control the associated production and transportation cost. Recently, injection of paraffin inhibitors in the transportation pipelines has been widely used along with other strategies to improve production. This study investigates the effect of operating temperatures and geometries on the performance of paraffin inhibitors. Moreover, the experimental temperature differences (i.e. changes in coolant temperature and bulk oil temperature) strongly influence the inhibitor efficacy indicating that these conditions must be optimized prior to field applications.

The experiments were conducted with a Caspian Sea (CS) condensate at different temperature conditions using two paraffin inhibitors (Maleic anhydride co-polymers: PI-B and PI-C, where PI-B has a higher carbon chain length than PI-C). The inhibitor concentration of 500PPM and a 24h time duration is maintained for all the experiments. The deposit mass and wax content were analyzed.

Wax mass flux increases with the increasing temperature difference in constant bulk oil temperature experiments. In contrast, the mass flux increases first and then decreases with the decrease in the temperature difference in constant coolant temperature experiments. Hence, it is important to consider the influence of operating conditions that may change the oil properties significantly and ultimately the magnitude of the paraffin deposition. Deposit mass (decreased) and wax content (increased) are significantly influenced by the presence of inhibitors. The inhibitor efficacy, that incorporates both deposit mass and wax content, is calculated at different operating temperature differences. It has been observed that the efficacy strongly varies with the operating region. Hence, it is necessary to select proper inhibitors based on the local operating temperature conditions during injection.

This study provides a fundamental understanding between operating parameters and inhibitor efficacy. The usage of inhibitors is highly complicated and the knowledge obtained through this investigation disseminates crucial information on selecting proper inhibitor for field applications.
Automatic Flare Stack Monitoring
Authors: Janssen R. , Sepasian N.
Published: October 2017

Flare stacks must be continuously monitored to assure ignition of released gases during the plant operation. The process of flare detection is generally referring to detecting the presence or absence of a flare. Flare monitoring adds the capability of tracking the size of the flare to this process. By setting lower and upper monitoring boundaries an alarm can be generated if the flare becomes too small or too big. Reliable flare stack monitoring becomes significantly crucial to ensure no unburned toxic or waste gas is released into the atmosphere causing environmental issues and possible fire hazards. It also gives the operator an extra handle to optimize the production process. In this paper, we introduce an automatic flare detection and monitoring system. Our user-friendly system is computer vision based, plug-and-play and designed as a built-in part of the camera. Taking advantage of the geometrical properties of the flare as well as temporal information obtained by video analytics, we create a monitoring system robust to various parameters such as wind direction. Based on our knowledge, we are the first to present an automatic flare stack monitoring system with flare size tracking and automatic event signaling. Our presented system has been tested for live monitoring in the Rotterdam Botlek area, The Netherlands. The preliminary results illustrate a reliable system which is free of false alarms.
An Experimental and Modeling Study of Solvent-Bitumen Phase Behavior at Elevated Temperatures Using Cold Lake Bitumen
Authors: Eghbali Sara , Dehghanpour Hassan
Published: October 2017

Co-injection of CO2 or light hydrocarbons with steam in SAGD (Steam Assisted Gravity Drainage) process may enhance bitumen mobility and reduce Steam Oil Ratio (SOR). Understanding and modeling the phase behavior of solvent-bitumen system are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and modeling study is undertaken to characterize the phase behavior of bitumen-CO2 and bitumen-C4 systems. Produced and dewatered oil from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater formation. Constant composition expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2-bitumen mixture, and C4-bitumen mixture. The Peng-Robinson equation of state (PR-EOS) is calibrated based on the measured data and used for PVT modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 120 °C to180 °C. Further to that, dead oil viscosity measurements are conducted at similar temperature intervals to estimate oleic phase viscosity.

According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than CO2 at reservoir pressure of 580 psia (4,000 kpa) and temperature range of 120 °C to 180 °C. During the CCE tests, co-existence of three equilibrium phases is observed for the C4-bitumen system with 84 wt.% C4. The three phases consist of a solvent-lean (bitumen-rich) oleic phase (L1), gaseous phase (V) and a solvent-rich (bitumen-lean) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into L2 phase and preserve the heavy components in L1 phase. It is observed that the color of L2 phase becomes lighter by decreasing the pressure which may suggest extraction of lighter hydrocarbon components at lower pressures. Similar tests on the CO2-bitumen system only shows two effective phases over a similar temperature range. The two phases consist of a solvent-lean (bitumen-rich) oleic phase (L1) and a gaseous phase (V).

By using the regressed EOS model, phase equilibrium regions are predicted in the compositional space for the solvent-bitumen system. EOS predictions indicate two types of two-phase regions in composition space for C4-bitumen system (i.e., L1-L2 in temperature range of 120 °C to 148 °C and L1-V in temperature range of 148 °C to180 °C). However, only one type of two-phase region (i.e., L1-V) exists in the similar temperature range for CO2-bitumen system. The EOS predictions show that 1.7 wt.% CO2 can reduce bitumen viscosity by up to 4 times, and 8.7 wt.% C4 can reduce bitumen viscosity by up to 32 times in temperature range of 120 °C to 180 °C.
A Rigorous Solution to the Problem of Phase Behavior in Unconventional Formations with High Capillary Pressure
Authors: Neshat Sajjad S. , Okuno Ryosuke , Pope Gary A.
Published: October 2017

Phase behavior of hydrocarbon mixtures is affected by the petrophysical properties of the formation. This paper integrates several important thermodynamic and petrophysical aspects of the problem in a rigorous way, and introduces a solution that can be applied over the range of pore sizes in tight and shale formations in which hydrocarbons can be practically recovered. A new criterion for phase stability analysis is introduced that results in discovery of a new range of solutions for the capillary equilibrium problem. A novel three-phase capillary pressure model has been used to estimate the effect of connate water on the gas-oil capillary pressure. The model is then used in conjunction with the new stability method to solve several phase behavior problems for binary and multi-component reservoir fluids. We show that the new approach can significantly improve the estimation of phase behavior at high capillary pressure.
Modeling of Production Decline Caused by Fines Migration in Deep Water Reservoirs
Authors: Tan Yunhui , Li Yan , Wu Ruiting , Rijken Peggy , Zaki Karim , Karazincir Oya , Williams Wade , Wang Bin
Published: October 2017

Many deep water wells experience steep productivity declines. Some field observations indicate that this decline is partly attributed to fines migration effects. This paper presents a numerical workflow to simulate the effect of flow induced fines migration on production decline over time in deep water reservoirs. A permeability reduction function is extracted from long-term core flood tests and implemented into a reservoir simulator. Using the permeability reduction function, production degradation caused by fines migration is simulated in a detailed single well model. From previous research, it is understood that fines migration won't start until the flow velocity is greater than the critical velocity. Through many long-term core flood tests (extended fines migration test), we conclude that the permeability damage induced by fines migration is a function of the pore volume throughput. To address these observations the numerical model is updated such that the interstitial flow velocity is tracked in each individual cell. When the interstitial velocity is greater than the critical velocity, the cell's permeability follows the permeability reduction trend obtained from laboratory data. If the flow direction is reversed, fines migration damage will be recovered. A detailed 3D model is constructed to study the fines migration effect in each part of the wellbore (perforation, fracture etc.) and reservoir. As expected, fines migration starts near the perforation where flow velocity is highest. Depending on the permeability decline rate, the production asymptotes to a constant value after a certain period of time. Both the decline rate and the ultimate residual permeability have a strong effect on the final production. Sensitivities were run to study the effect of fines migration in different completions. As the author's understanding this is the first time that laboratory-based fines migration data is incorporated into a reservoir simulator to predict the production decline using experiment-based fines migration functions. This workflow will help reservoir engineers to predict the damage caused by fines migration, predict production decline and plan remediation.