bluuebunny/crossref_metadata_2025 huggingface dataset:
Smart Unconventional Approach to Universal Oil-Based Mud Removal Using High-Performance Bio-Micromaterial
Authors: Pernites Roderick , Clark Jordan , Fu Diankui
Published: September 2019

Using a single universal spacer surfactant to clean a wide variety of oil-based mud (OBM) is considered the "Holy Grail" of spacer fluid system. Specialty chemical and service companies have devoted intense research and vast resources to develop the ideal spacer surfactant, but their efforts have not led to a singlesurfactant solution due to uniquely different drilling mud properties. It is no surprise to experts in the field that surfactant selection is extremely mud specific. For instance, one surfactant may effectively clean certain types of OBM, but fail in another mud from a different location that has the same density and base fluid. As a result, service companies have numerous surfactants in their portfolios, further complicating logistics and operations. This paper presents the discovery of a high-performance universal biomicromaterial, which can significantly improve the cleaning performance of any surfactants/spacer fluids to remove most, if not, all types of drilling mud. The innovative bio-micromaterial is an eco-friendly byproduct from another industry.

Successful cleaning of the drilling mud was demonstrated by standard rotor testing with different OBM samples from across North America, and the percentage of mud removal was determined. Furthermore, the ability of the innovative micromaterial to efficiently clean the mud was verified by measuring the strength of bonding between the set cement and the metal casing that had been cleaned by the spacer fluid after drilling mud contamination. Basically, this new procedure simulates downhole fluid displacement by the intermediate spacer fluid, which is ahead of the cement slurry, displacing the mud. Stability and mixability were also studied to determine the effect of the bio-micromaterial addition to the spacer fluid. Finally, a fundamental scientific study using thermogravimetric analysis and imaging techniques was done to characterize the material and determine its thermal stability.

For the first time, newly discovered, high-performance, universal cleaning micromaterial is presented to enhance the OBM removal of any spacer fluid design. This groundbreaking research has successfully demonstrated the unconventional advanced material to be a universal cleaning, single-additive spacer admixture for a wide variety of drilling mud from various regions across North America. To our knowledge, based on extensive literature search, this is the first report about the application of this natural waste product in wellbore cleaning fluids like the spacer.
Maximizing Value from an Investment in Geophysics
Authors: House Nancy , Mencin Alan
Published: September 2019

It is well known that geophysics, particularly the reflection seismic method, significantly changed the probability of economic success for conventional hydrocarbon deposits over the past 100 years. Astechnology improved theimages could be leveraged to determine the presence of gas and also thereservoirproperties of the rock themselves. As unconventional resource plays took off, many North American Basins have been carpeted with high quality 3D seismic that is routinely be exploited to reduce drilling risks, improve completion efficiency and high-grade acreage based on seismic indicators of Total Organic Content(TOC), brittleness, or ‘fracability’. But as the capabilities increased so did the cost. Proprietary acquisition underwritten by a single company was restricted to companies with largegeologic and geophysical budgets. Speculative data acquisitionand licensing was employed more and more to reduce the cost of 3D seismic toindividual companies. Thegeophysical companies underwrote the cost of 3D seismic surveysexpecting to makeenough to cover costs through licensing arrangements and hopefully make a profit. This was done by licensingthe data to numerouscompanies. Each of the licensees wouldthen get the benefit of the seismic data where it was needed at a fraction of the cost of proprietary acquisition. Lately the use of high-quality 3D seismic integrated with reservoir, completion and production data is used tolowerdrilling risks, high grade acreage and quantify the extent of unconventional resources. (Stephen Rassenfoss, JPT Emerging Technology Senior Editor, 2015) The technical requirements of gathering and processing the seismic data that allow the extraction of reservoir and rock properties from tight rocks and shale reservoirs are high and consequently also very costly. How can the maximum value be extracted from the investment? The investment in 3D seismic for conventional and unconventionalreservoirs must be carefully weighed against the economic benefits. We propose a simple method to evaluate the investment in seismic using simple decision analysis coupled with expressing the cost in ways that are applicable to the full economic benefit of the data.
Data-Driven Model for the Drilling Accidents Prediction
Authors: Antipova Ksenia , Klyuchnikov Nikita , Zaytsev Alexey , Gurina Ekaterina , Romanenkova Evgenia , Koroteev Dmitry
Published: September 2019

Majority of the accidents while drilling have a number of premonitory symptoms notable during continuous drilling support. Experts can usually recognize such symptoms, however, we are not aware of any system that can do this job automatically. We have developed a Machine learning algorithm which allows detecting anomalies using the drilling support data (drilling telemetry). The algorithm automatically extracts patterns of premonitory symptoms and then recognizes them during drilling.

The machine learning model is based on Gradient Boosting decision trees. The model analyzes real time drilling parameters within a sliding 4-hour window. For each measurement, the model calculates the probability of an accident and warns about anomaly of particular type, if the probability exceeds the selected threshold.

Our training sample comes from 20+ oilfields and consists of sections related to 80+ accidents of the following types: stuck pipe, mud loss, gas-oil-water show, washout of pipe string, failure of drilling tool, packing formation, that occurred while drilling, trip-in, trip-out, reaming.

We have designed the prediction model to work during drilling new wells and to distinguish the normal drilling process from the faulty one. One can configure the anomaly threshold to balance amount of false alarms and the number of missed accidents.

To evaluate quality of the model we measure such data science metrics as ROC AUC score and confusion matrices. While testing model can identify 24 accident from 30 with high confidence, whereas for the others there is still a room for improvement. Our findings suggest that including more accidents of underrepresented types will improve quality. Other data science metrics also support aptitude of the model. Finally, having data from multiple heterogeneous oilfields, we expect that the model will generalize well to new ones.

This paper presents a good practice of development and implementation of a data-driven model for automatic supervision of continuous drilling. In particular, the model described in the paper will assist specialists with drilling accidents prediction, optimize their work with data and reduce the nonproductive time associated with the accidents by up to 20%.
Robustness of Novel Low-Tension Gas LTG Floods in High Salinity and High Temperature Reservoirs
Authors: Nguyen Nhat , Ren Guangwei , Mateen Khalid , Ma Kun , Luo Haishan , Neillo Valerie , Nguyen Quoc
Published: September 2019

Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.
Understanding Heel Dominant Liquid Loading in Unconventional Horizontal Wells
Authors: Kannan Subash , Nagoo Anand , Lea James
Published: September 2019

As a common occurrence in production operations, liquid-rich horizontal gas (and gassy oil) wells in unconventional plays develop severe instabilities at different stages of their well life. In this novel work, we first quantify the three-phase gas-oil-water multiphase flow behavior leading up to the characteristic severe loading signatures in order to better understand the dynamic heel-dominant liquids loading. Then, we demonstrate how a simple analytical diameter-and-inclination-dependent critical gas velocity equation can be used to determine the onset of the severe loading instabilities in a variety of artificial lift/liquid loading mitigation strategies, namely end-of-tubing landing (EOT), tubing/casing sizing, gas lift variations and tail pipe/dip tube. Actual high frequency bottom hole pressure data along with measured surface conditions will be used to evaluate the slugging behavior and recreate using analytical multiphase flow simulator. The flow conditions will be extrapolated to the heel/near lateral section of the well and simulated for various lift strategies.
Novel Non-Aromatic Non-Ionic Rheology Modifiers for High Paraffinic Crude Oils
Authors: Sokhanvarian Khatere , Diarra Alfa , Fernandez Jorge , Stanciu Cornell
Published: September 2019

Wax and paraffin precipitation is a major problem around the world, costing the petroleum industry billions of dollars yearly. As temperature drops below the Wax Appearance or Wax Precipitation Temperature (WAT/WPT) of crudes, paraffin starts to precipitate out and restrict or block the effective flow. There are different methods, such as mechanical and chemical remediation to deal with wax issues. Among the latter ones, the use of surfactants is favorably looked upon since they are small molecules with surface activity properties. This study aims to introduce novel aliphatic non-ionic surfactants with different chain length and degree of ethoxylation. In addition to chain length, the impact of branching on the hydrophobic part of the surfactants was also studied.

A waxy crude oil from Brazil was characterized through determining its carbon distribution, WAT, viscosity and density based on industry standard methods. Several surfactants with different combinations of chain length/ethoxylation number were then selected for screening. The performance of surfactants was evaluated based on data obtained from treated crude versus the control sample through different experiments. Rheology studies were conducted at 50 to -10°C and at shear rates of 5 and 300 s-1. The cold finger instrument was utilized to determine paraffin content of the untreated and treated crude. Finally, the paraffin crystal size was analyzed through microscopic studies.

The results showed that shear rate can affect the wax treatment outcome as well as the effective concentration of surfactant. Therefore, it is important to assess the rheology at high and low shear rates. Some surfactants in the present study performed great at both low and high shear rates and were able to reduce the viscosity by 80% at temperatures well below WAT of the crude oil. The microscopy results confirmed that wax crystals were reduced in size and were more dispersed after treating the crude with these surfactants. The findings from High Temperature Gas Chromatography showed that the deposition of heavy fraction part of crude (C40+) is reduced after treating the crude oil with the surfactants in the present study.

The current study addresses the wax precipitation/deposition challenges of heavy crudes and proposes mitigating them through the use of some new non-aromatic non-ionic surfactants. The chemistries and findings of this research help the oil and gas industry to save money and time by mitigating flow assurance problems.
Semi-Analytical Modeling of Multi-Mechanism Gas Transport in Shale Reservoirs with Complex Hydraulic-Fracture Geometries by the Boundary Element Method
Authors: Zhang Miao , Sun Qian , Ayala Luis F.
Published: September 2019

This work proposes a novel boundary-element based approach to model fluid transport in unconventional shale gas reservoirs with complex hydraulic fracture networks. The fluid flow model employed in this work considers multiple fluid transport mechanisms identified in in gas transporting process in shale nanopores including diffusion, sorption Kinetics, Knudsen diffusion, and sorbed-phase surface diffusion. Accordingly, two governing partial differential equations (PDEs) are written for free and sorbed gases. In the proposed method, boundary integral formulations are analytically derived using the fundamental solution of the Laplace Equation for two governing nonlinear PDEs and Green's second identity. The domain integrals considering the nonlinear terms due to multi-mechanism effects, are transformed into boundary integrals employing the dual reciprocity method (DRM). The resulting boundary integral equations for free and sorbed gas later are solved in terms of a series of discrete nodes after coupling with fracture flow model. The validity of proposed solution is verified using several case studies through comparison with a commercial finite-element numerical simulator COMSOL.
Lessons Learned from Effective Well Integrity Management in Offshore Field
Authors: M. Al-Dhafeeri Abdullah , Fouad Abo Zkery Shebl , Ahmed Al Sdeiri Saad
Published: September 2019

Offshore field started on operation to produce crude oil with 27 API° as sweet crude and sour crude with 32 API° since 1960. Large number of wells in offshore field revealed undesirable phenomena related to well integrity issues as potentially sustained pressure on several casing strings. Well integrity management emphasis on preventing well problems related to well safety and integrity such as casing leak, Sustained Casing Pressure (SCP), downhole safety valve (DHSV) failures. The direct impact from integrity management added great value in terms of decreasing in operating down time, improvement in well control and safety aspects, and reducing unplanned repair intervention. In addition, the loss of well integrity can cause major accidents with a severe risk to the personnel, asset and environment.

The paper aims to illustrate a methodology results on applying effective well integrity monitoring techniques. A focus was made to improve monitoring well integrity through reviewing wellhead surface parameters, annulus sections pressure and downhole condition. In addition, the subject wells should be kept under close monitoring at a safe operable with an integral condition. Non-integral wells are common in aged wells, which are becoming a challenging issue to restore its integrity and operability especially for such aged completion. As a part of well integrity review, the concerns had been identified, investigated, and subsequently mitigations actions are recommended to restore the well integrity. Currently, it is confirmed that 25 oil producers with casing leak problems, which resulted to be converted from conventional completion to a slim hole with limited future accessblity. Based on lab reusltes and logging interpretations, it is indicated that the root cause of casing leaks is due to corrosive water flow from shallow aquifer formation. Therefore, an immediate remedial action is required to improve well construction.

A successful worked over well with integrity issue as a casing leak was repaired by cement squeeze into across the corroded casing interval, which enhanced well integrity and restore well productivity. The resulted showed that tubing leaks encountered with well integrity due to sustained casing pressure. Therefore, the pressure on production casing can cause severe failure with catastrophic damage. The results also illustrated that a water flow through poor cement is a major cause of sustained casing pressure in the outer casing strings. The cause of pressure on production casing is generally easier to diagnose than that pressure on one of the outer casing strings. Challenges, methodology, work schedule, risk assessment, lesson learned and findings are included in this paper. The effective well integrity management resulted on great deal of benefits, which are related to securing wells, well operability, cost saving, and sustained maximum production target.
Low Cost Recovery Optimization of Mature Onshore Sour Gas and Gas Condensate Assets
Authors: Maierhofer Matthias , Pamminger Johannes , Ecklmair Andreas , Schuster Markus , Lamar Justin , Otto Volker , König Joachim
Published: September 2019

Two mature onshore gas condensate fields, treated in one sour gas plant, are investigated with the objective to increase their recovery and to extend their economic field life. The impact of a surface pressure reduction on both reservoir delivery and facility operability is examined.

A predecessor project successfully proved the capability of the sour gas plant to treat declining gas flow rates under a wide pressure range from some 70 bara down to about 14 bara. This paves the way for an integrated method looking at stepwise pressure reduction in the whole system from the wellheads via the compressor stations and down to the sour gas treatment plant. In an iterative approach the outcomes of a subsurface PETEX model, a surface HYSYS model and compressor capacity calculations are matched. Production rate and system pressure are predicted versus time.

It is fundamental that the capacities of the reciprocating machines in the compressor stations can be increased by lowering their discharge pressures. The higher capacity achieved through lower discharge pressure in turn reduces wellhead pressures and, in consequence, enhances recovery. Respective subsurface and surface modeling and engineering studies indicate the feasibility of a system pressure reduction and the positive effects on recovery and process safety.

In particular, full system test runs covering most of the anticipated pressure ranges and specific compressor tests confirm the modeling and engineering results. Compared to other scenarios involving additional compressors a CAPEX reduction of 85% is achieved. Also 40% OPEX per year are saved. Although these latter scenarios with more/bigger compressors allow for a quicker pressure reduction at the wellheads and higher revenue, their high costs more than offset their revenue advantage over the optimized approach.

The low cost scenario increases ultimate gas recovery by 5% compared to the Asset Base. In total, the economic field life is extended by approximately six years. Additionally, the process safety increases due to the lower system pressure.

Low cost and optimized production solutions in mature onshore gas assets can only be developed using a strongly integrated multidisciplinary approach. The entire production system from the reservoir to the sales gas handover point must be considered. Notably, the suggested system pressure reduction in declining fields works with complex sour gas plants and with reciprocating compressors.
Mechanics & Effectiveness of Different Types of Diversion in Horizontal Well Fracturing
Authors: Daneshy Ali
Published: September 2019

Use of diverters for altering fluid distribution among created hydraulic fractures in horizontal wells has gained popularity in recent years, both for initial and re-fracturing treatments. Aims in initial fracturing treatments have included creating more uniform distribution of slurry within the created fractures, increasing stage efficiency by reducing the number of pumping stages while increasing the number of clusters per stage, increasing the number of fractures created in openhole completions, reducing interactions between fractures in adjacent horizontal wells, etc. In re-fracturing treatments, a popular application is for altering fluid distribution in wells re-treated without isolation between stages (Pump & Pray/Bullheading) with the intent of increasing the number of re-activated fractures and initiating new fractures through added perforations.

Engineering analysis of the mechanics of fluid diversion has not received the same degree of attention as its use. The reported discussions are often limited in their scope, two-dimensional in structure, and somewhat speculative in their conclusions.

This paper divides the targets of diversion into three categories; at the wellbore/perfs, near wellbore, and deeper inside the fracture. It divides the types of diverters into three categories, mechanical, solid particulate (including proppants), and chemical. The applications are divided into two categories, initial and re-fracturing, together with highlighting their differences and requirements for successful diversion. The paper discusses how presence of proppant changes the fluid distribution in favor of more conductive perforations. It considers the fracture as a three-dimensional structure, extending on both sides of the wellbore. It describes how different diverting agents cause fluid redistribution between the fractures, and the important role of proppant in some applications. It shows that as the target of fluid diversion moves away from the wellbore the chances of its success become smaller and more unpredictable, while also the time before effective diversion takes place becomes longer.

Comprehensive understanding of the mechanics of fluid diversion helps in the selection of the type of diverter and how best to deploy it for achieving specific objectives and results.
Frac Hits: Good or Bad? A Comprehensive Study in the Bakken
Authors: Krishnamurthy Jayanth , Srinivasan Karthik , Layton Neil , Drouillard Matthew
Published: September 2019

Frac hits are a persistent phenomenon that operators face periodically during unconventional field development. With basin maturity and infill drilling, frac hits play a major role in dictating overall production from multiwell pads. This paper focuses on the causes of frac hits and their subsequent impact on well EURs with solution methods to minimize negative impacts resulting from frac hits.

A fully numerical model-based was built around a four-well pad in Mountrail County, N.D., by integrating high-tier data including 3D sonic logs, nuclear magnetic resonance imaging and downhole spectroscopy to build a mechanical earth model of the reservoir. The parent well(s) are history-matched and geomechanical properties recalculated to changes in in situ stresses from parent well production. Infill wells are evaluated for asymmetric frac propagation toward depleted wells, and EURs are estimated to compare with thosethat of the parent wells.

The initial well stimulation program and the volume of production from the parent well has a huge impact on the degree of fracture asymmetry in infill wells. This preferential propagation creates additional stimulated surface area between wells. If the parent well was understimulated in the first place, the infill wells in general result in a positive frac hit, and additional barrels of oil are produced from the parent well with little or no impact on the infill well. However, if the parent well has been on production for a long period the hydraulic fracturing treatment deposits a huge volume of fluid and proppant in already depleted areas, and the reservoir pressure is not sufficient to flush out the excess water. This causes the parent well to experience a surge in water cut and reduction in oil rate for an extended period. In addition, the infill well's initial production will not metch the parent well IPs, and EUR can reduce drastically. This paper will categorically illustrate the timing, spacing and stimulation recommendations to minimize or mitigate these impacts.

Quantifying frac hits requires a comprehensive multiwell approach incorporating geomechanics, fracturing and production. This paper showcases case studies from the Bakken, identifying fracture asymmetry and production forecast from multiple wells, carefully considering all the physics, rock and fluid interaction in the subsurface strata. This will be a valuable tool for the engineers and geologists in the oil and gas community to effectively plan future infill development programs in unconventional reservoirs.
Triaxial Testing System for Seismic Frequencies Measurements with Laser Displacement Sensors
Authors: Lu Chuan , Brandl Jakob , Deisman Nathan , Chalaturnyk Richard
Published: September 2019

In this study, a novel experimental system has been developed for static and dynamic elastic properties measurements at seismic frequencies under anisotropic stress and shear deformation conditions. This system focuses on static and seismic range frequencies dynamic (0.1 Hz to 20 Hz) elastic deformation properties of poorly consolidated oil sands and highly overconsolidated (clay) shales. The main body of the experimental system is a computer control servo-hydraulic system. A pair of laser displacement sensors measure nanometer scale displacement during the dynamic tests. A coarse scale and fine scale load cell system was developed for measuring force with high precision during dynamic testing. A novel triaxial cell for use with the loading system was also developed to simulate the reservoir stress and pore pressure condition during static and dynamic testing and allows permeability to be measured during testing. The loading system, dual load cell calibration procedure and results, and results for acrylic and 3D printed sand specimens are presented. The stable and reasonable results demonstrate the capacity of the new experimental system.
Can You Feel the Strain? DAS Strain Fronts for Fracture Geometry in the BC Montney, Groundbirch
Authors: Ugueto Gustavo A. , Todea Felix , Daredia Talib , Wojtaszek Magdalena , Huckabee Paul T. , Reynolds Alan , Laing Carson , Chavarria J. Andres
Published: September 2019

The use of Distributed Acoustic Sensing for Strain Fronts (DAS-SF) is gaining popularity as one of the tools to help characterize the geometries of hydraulic fracs and to assess the far-field efficiencies of stimulation operations in Unconventional Reservoirs. These strain fronts are caused by deformation of the rock during hydraulic fracture stimulation (HFS) which produces a characteristic strain signature measurable by interrogating a glass fiber in wells instrumented with a fiber optic (FO) cable cemented behind casing. This DAS application was first developed by Shell and OptaSense from datasets acquired in the Groundbirch Montney in Canada. In this paper we show examples of DAS-SF in wells stimulated for a variety of completion systems: plug-and-perforating (PnP), open hole packer sleeves (OHPS), as well as, data from a well completed via both ball-activated cemented single point entry sleeves (Ba-cSPES) and coil-tubing activated cemented single point entry sleeves (CTa-cSPES). By measuring the strain fronts during stimulation from nearby offset wells, it was observed that most stimulated stages produced far-field strain gradient responses in the monitor well. When mapped in space, the strain responses were found to agree with and confirm the dominant planar fracture geometry proposed for the Montney, with hydraulic fractures propagating in a direction perpendicular to the minimum stress. However; several unexpected and inconsistent off-azimuth events were also observed during the offset well stimulations in which the strain fronts were detected at locations already stimulated by previous stages. Through further integration and the analysis of multiple data sources, it was discovered that these strain events corresponded with stage isolation defects in the stimulated well, leading to "re-stimulation" of prior fracs and inefficient resource development. The strain front monitoring in the Montney has provided greater confidence in the planar fracture geometry hypothesis for this formation. The high resolution frac geometry information provided by DAS-SF away from the wellbore in the far-field has also enabled us to improve stage offsetting and well azimuth strategies. In addition, identifying the re-stimulation and loss of resource access that occurs with poor stage isolation also shows opportunities for improvement in future completion programs. This in turn, should allow us to optimize operational decisions to more effectively access the intended resource volumes. These datasets show how monitoring high-resolution deformation via FO combined with the integration of other data can provide high confidence insights about stimulation efficiency, frac geometry and well construction defects not available via other means.
Examining Hydraulic Fracture Characteristics Based on Induced Microseismicity: A Barnett Shale Case Study
Authors: Jia Suzie , Wong Ron , Eaton David
Published: September 2019

Microseismicity can be triggered by various dynamic processes related to a hydraulic fracturing treatment. These processes alter the in-situ stress field inside and around the stimulated reservoir volume, due to both creation of new fractures and fluid leakoff into the surrounding rock matrix. The analysis of spatiotemporal dynamics of fluid-induced seismicity can reveal important characteristics of the hydraulic fracturing process. With the knowledge of treatment data, it can be used in conjunction with the reservoir geomechanical theories in hydraulic fracture growth to investigate the fracture geometry and fluid-rock interactions. By applying these theories to a real microseismic dataset, two types of triggering front expansion patterns are evident. With the presence of a dominant hydraulic fracture, the radius of the triggering front expands linearly with time. Moreover, the microseismic event cloud forms a planar shape with low opening angles (failed by shear), indicating fracture slippages around the major hydraulic fracture. On the other hand, in the case of a complex fracture network with the absence of any major hyfraulic fracture, the triggering front grows non-linearly with time. This scenario can be treated as equivalent to a diffusion model and the microseismic events exhibit a higher fracture of tensile components (either opening or closing) and an equidimensional event cloud. In this study, two stages were analyzed and the derived fracture widths and fluid-loss coeffcients fall into a realistic range of general observations in the context of these two theories.
An Electronic Rig Action Plan - Information Carrier Equally Applicable to the Driller and the Automation Platform
Authors: Solvi Lars-Jørgen Ruså , Revheim Olav , Schaefer Serafima , Schutte Frank Johan
Published: September 2019

By use of the proposed method for digitilizing operation procedures and activities, the rig action plan can become the dynamic information exchange platform between planning and execution phase. Digitilizing the workflow and structuring the information in a rig action plan enables engineers to plan operations and transmit procedures and related parameters in a consistent form applicable to the driller and the drilling control system's automation platform.

The paper reviews existing rig action plans and activities to demonstrate how structuring of information using the new methodology allows planned procedures to be readable by a drilling automation platform. A new data structure with multiple activity levels is proposed for the rig action plan. The requirements and concept of a new application program interface (API) is discussed. The result of applying the proposed methodology to an actual rig action plan is presented along with an overview of a pilot project. The benefits of digitalizing the workflow and implementing an open, structured, machine readable rig action plan demonstrate how the new approach will contribute to the oil and gas technologies ambition to automate operation.
Paradox of Control in Large Project Organizations
Authors: Duhon Howard , Braathen Petter
Published: September 2019

Most major projects fail(Merrow, 2011). Failure results from a lack of control

Failures occur most often and most ruinously on our largest and most important projects. But these are the projects that are subjected to the most rigorous management oversight and control. There appears to be a paradox here: Those projects that we control the most rigorously appear to be the most out-of-control.

We argue that this paradox is caused by control models rooted in the reductionist/Newtonian worldview that is not suitable for understanding and controlling today's complex projects.

We argue that management control models can be improved by making them more like the control models extant in naturally occurring complex systems which do not experience any paradox of control.
A Case Study Demonstrating Single Relief Well Contingency for a Prolific Gas Well in Ultra-Deepwater
Authors: Oskarsen Ray T. , Paknejad Amir , Chantose Prasongsit , Emilsen Morten , Morry Brett
Published: September 2019

A blowout contingency plan was made for a gas field in a remote area with water depth exceeding 1600 m. The worst-case discharge analysis for a representative well in the field concluded that the reservoir is capable of producing at a highly prolific rate, which posed a challenge when developing a source control contingency plan that complies with governing regulators’ and operators’ internal requirements. Simulations using a transient multiphase flow simulator showed that the kill requirements could exceed the capability of a single conventional relief well; however, planning to intersect and coordinate a dynamic kill using multiple relief wells involved unacceptable operations risks. Furthermore, considering rig availability, limited pumping resources, and long mobilization times for this region, planning to use multiple relief wells is not a feasable option.

A recently developed subsea flow spool system can eliminate the need for multiple relief wells in the case of potentially hard-to-kill blowouts, especially where a dynamic kill using multiple relief wells would involve unacceptable operations risks. Dynamic kill simulation shows that the subsea flow spool, coupled with a supporting mobile offshore drilling unit (MODU), flexible flow lines, a supplementary flow spool, and a casing string placed inside the riser will be able to achieve a successful kill if needed. Furthermore, detailed engineering analysis of triaxial loads, fatigue, and erosion were done for critical hardware components to ensure all potential failure points were addressed. In conclusion, the subsea flow spool is a key component of demonstrating a single-relief well contingency for potentially hard-to-kill blowouts
An Industry Look at the Petroleum Engineering Curricula
Authors: Rietz Dean , Soliman Mohamed , Cagle Adam
Published: September 2019

During the last few years, the petroleum industry has been experiencing significant changes in various areas including, workforce, targets of exploration, application of (new) technologies, and general operational areas of focus. A prolonged depression of oil prices, changes in geopolitical atmosphere, the rise of investment in unconventional resources, as well as the implementation of emerging technologies (including digital) have been the primary catalysts of change within the industry. In terms of workforce, these changes have produced leaner organizations, along with the unintended consequence of losing some critical expertise and creating knowledge-gaps at many organizations. The changes, particularly in technology, necessitate a look at the need for the acquisition of new skills, for current and future petroleum engineers, that match new areas of interest – such as data analytics and artificial intelligence.

As the oil industry continues to evolve, it is imperative for academic organizations to consider these changing dynamics and be responsive. This paper outlines the results of a recent survey that targeted industry managers or supervisors who have direct experience with newly minted petroleum engineering graduates (less than five years of experience). The survey asked the participants their opinions regarding the preparedness of recent graduates as they enter the workforce. The survey's intent was to identify the potential need to modify the skills and knowledge currently acquired in academic institutions during the undergraduate study.

A comprehensive survey that posed questions regarding classical and contemplated new petroleum engineering curriculum was sent to recipients, primarily within the reserves and reservoir-engineering sector. The recipients were industry professionals working in operating, service, financial, and consulting sectors of the petroleum industry. More than 200 responses were received. The tabulated results are presented in the paper, along with interpretation of the results. The raw data will be made available through OnePetro as an accompaniment to the published paper.

The paper presents the survey conclusions, proposed action items, and discusses plans for a follow-up survey.
An Assessment Of The Current Regulatory Frameworks For Onshore, Upstream, Unconventional Well Integrity And Strategies For Improvement
Authors: Thomas Tim , Johnson Jr. Raymond L.
Published: September 2019

This paper reviews existing analysis of well integrity related regulation in upstream unconventional oil and gas projects and proposes a methodology to enhance such regulation in the future.  This paper has compiled findings from a number of peer-reviewed sources assessing regulatory systems across a number of jurisdictions. These findings were based around four key questions that this paper has assessed (1) what is the overall assessment of current regulatory systems; (2) where to-date are the key areas that current research have focused on; (3) what are the key strengths identified in current research; and (4) what are the key gaps in current research? 

This paper demonstrates that the body of work provides a wide array of assessments and conclusions. Whilst some are quite explicit in their judgment of a particular system’s effectiveness, many refrain from making a holistic assessment in a particular jurisdiction. Much of the research involves the application of prisms, such as environmental risks or local government jurisprudence. Along with these prisms, a number of common aspects of research are identified that strengthen the analyses, such as the use of ‘as drilled’ data and the use of relevant data samples. Some research gaps remain despite these strengths.

The majority of previous researchers can identify some degree of ineffectiveness in various regulatory regimes. Further, a number of gaps exist as a result of regulatory systems being incomplete or inadequate, potentially masking other inadequacies. To address these gaps, this paper proposes a methodology to improve and clarify knowledge and practical recommendations to improve the effectiveness of assurance activities by both regulatory agencies and operators. Specifically, this methodology focuses on a typological assessment of written rules in a number of jurisdictions. As an example, we present an ‘as built’ dataset to assess compliance with rules and identify means of assurance. This methodology proposes surveying of regulatory agencies and operators to validate the assertion that gaps can be identified and corrected and provide more insight into how regulatory systems function and the systematic causes of gaps.
Collapse Ratings of Cold Expanded Line Pipe Used as Casing
Authors: Miller Rich , Stewart Craig , Owoeye Oladele , King Abe , Long Xin , McGill Randy
Published: September 2019

API Specification 5L (2018) pipe is commonly used as surface casing. Recent deepwater failures have led to a review of collapse performance of 5L pipe as part of the larger root cause investigation.

A survey of pipeline industry publications generated a database of over 80 collapse tests of cold-expanded line pipe. The data are compared to casing collapse ratings per API Technical Report 5C3 (2018) and to alternative ratings included in API Recommended Practice 1111 (2015) for offshore pipelines and in the submarine pipeline standard DNVGL-ST-F101 (2017). The comparison showed that the pipeline ratings provide a better fit to the collapse data and that API TR 5C3 overpredicts collapse performance of the subject pipe.

Further investigation revealed that, for two operators, the vast majority of offshore surface casing is line pipe that has been cold-expanded without stress relief. Several risk mitigation alternatives were considered. In the short term, the risk can be managed through learning bulletins, design guidelines and operational procedures. The preferred mitigation is to change the collapse rating for cold-expanded line pipe used as casing. This is a long-term solution involving industry standards and the subsequent adoption through commercial design software.

The work described in this paper has led to a ballot change for the next edition of API TR 5C3. This paper is presented to provide drilling industry awareness of the lower collapse performance of cold-expanded line pipe and to add context for selection of an appropriate alternative rating.
Augmented Reality: Simulation Enhanced Pressure Core Data
Authors: Erkal Alpay , Christensen Christopher , Powers Garwin , DesAutels Dave
Published: September 2019

Field development decisions are directly related to the original hydrocarbon in-place that leads to proper estimation of recoverable volumes and establish project economics. Oil and gas industry has had pressure core technology that is available to extract and preserve cores from reservoirs near in-situ conditions to determine hydrocarbon in-place values. Pressure core technology is an emerging one and prone to incomplete or partial data acquisition due to design limitations and inadequate implementations. Simulation modeling tool, typically used for reservoir modeling purposes, can augment the underperformances in data acquisition with a lab scale core simulation program.

Noble Energy has developed a modeling approach that allows hydrocarbon desorption rates from a pressure core sample to be simulated by emulating the lab conditions. Early time fluid losses for various reason such as fluid losses while encapsulating the core or during transport via wellbore and to the lab are common. Late time fluid desorption rates are difficult to obtain due to the time constraint that exists for performing experiments in the lab since it’s limited to hours to days timeframe. Both early and late time desorption rates can be augmented by simulation that yields better estimation of in-place volumes and expected recovery values over time while honoring the lab measured data in between.

Pressurized wireline rotary sidewall coring used by the vendors can have seal failures and the procedures implemented would not provide assurance of zero fluid losses since the mechanical equipment has expected operational limitations. The data obtained from such acquisitions may be deemed a failed experiment or even discarded if the losses cannot be quantified properly. Simulation enhancement revitalizes the data acquired and adds value to even partially successful pressure coring programs.

Noble Energy developed modeling approach to simulate fluid flow from the center of a core plug to the exterior surfaces of the plug emulating the lab environment complements the lab measurements even the pressure core had issues during and after acquisition. Simulation enhances pressure core data that may be incomplete or partially acquired based on possible early time losses and provide extended answers for late time desorption by eliminating impractical lab measurement timeframe. Reduced uncertainty in original hydrocarbon in-place volumes will allow better valuation of assets and robust field development plans.
Viscoelastic Polymer Injectivity: A Novel Semi-Analytical Simulation Approach and Impact of Induced Fractures and Horizontal Wells
Authors: Hwang Jongsoo , Sharma Mukul , Chiotoroiu Maria-Magdalena , Clemens Torsten
Published: September 2019

Several field cases reported that polymer injection in a horizontal well is a viable solution to increase oil recovery. The injectivity, however, may vary significantly depending on fluid, reservoir, and geomechanical conditions. Polymer injection without understanding these factors may lead to injectivity impairment, unswept zones, and fractures undesirable for the sweep. In this paper, we present a comprehensive viscoelastic polymer injectivity model for vertical and horizontal wells.

We developed a simulator to compute viscoelastic polymer injectivity by accounting for particle filtration, thermo-poro-elastic stress changes, fracture propagation, flow distributions among multiple layers, and viscoelastic polymer rheology. Simulation results clearly show that the contribution of shear-thickening characteristics on the polymer can have a large impact in un-fractured wells but have a much smaller impact in fractured injectors. The impact of geomechanical stress changes and subsequent induced fractures are also highlighted.

The model was then applied for a field case study to identify critical aspects needed to maintain high injectivity. Two field case wells are presented where water and viscoelastic polymer are injected for a vertical well and a horizontal well accessing the multi-layered reservoir respectively. For the two injectors, water was injected initially, and then HPAM polymer solution followed to improve oil recovery. Fracture growth and injection into a long horizontal lateral are the key factors that allowed the operator to maintain injectivity by reducing the Darcy velocity, shear rate, and shear-thickening zone. For a horizontal well, operating conditions are also identified by simulations to ensure matrix injection, which is the desired conformance and sweep improvement option.