bluuebunny/crossref_metadata_2025 huggingface dataset:
The Future Called; It Wants to Know Where Its’ Data is?
Authors: Murdoch Euan
Published: September 2022

This paper will review the current state of downhole wireless completion technologies. It sets out an optimized strategy for the selection of commercially viable systems and provides a discussion of the technical hurdles that that are still to be overcome

Technologies for real-time wireless downhole data acquisition exist but their widespread adoption has been limited. By relying on theoretical calculations and limited reservoir coverage, some operators are basing critical decisions on a limited picture. This could be during the deployment of completions, leading to a failure to reach total depth (TD) or recognize and deal in a timely way with well control incidents or during the production, where quantification of the reservoir parameters is beyond the reach of a single pressure/temperature gauge. This is typically due to a lack of a value calculation for these technologies, and this paper will set out the information needed to improve the decision process.

There are a number of key wireless communication technologies that exist commercially for downhole deployment. These are: acoustic, electromagnetic, radio frequency identification (RFID), pressure modulation, and timers. The strengths and weaknesses of each technology will be presented, and it will also be shown how they can be used to complement each other. A number of global case studies will be presented; these will show the successful deployment of these technologies and the benefits that were brought. This information will then be built on to show how a wireless system should be implemented to satisfy the operators requirements within the technical and financial constraints of today's landscape. Finally, it will highlight the technology gaps that exist that hold the industry back from a "perfect" solution.
IADC Code Upgrade: Interpretation of Surface and Downhole Data to Support Drilling Forensics
Authors: Watson William , Witt-Doerring Ysabel , Sugiura Junichi , Pastusek Paul , Daechsel Dustin , Vallet Laurent , Amish Mohamed , Oluyemi Gbenga
Published: September 2022

This paper establishes drilling surveillance interpretation and monitoring techniques for digital drilling data which can be used to support drilling forensics and improve drilling performance.

One significant advancement in the last 20 years has been the widespread availability and use of sensors to monitor all aspects of the drilling process. The majority of sensors will take surface and downhole data at several hundred samples per second, process the data and store a record at one sample per second. The data from these sensors are collated and processed using some form of Electronic Data Recording system. The information is subsequently displayed in realtime and stored for offsite transmittal. This paper extensively evaluates the impact on drilling performance due to how data from such sensors are collected, processed and the information displayed.

A number of observations are investigated, analyzed and explained identifying how data quality, consistency, frequency, sensor errors and data artefacts can skew the displayed results. This can critically impact the drilling forensic analysis and subsequent interpretation. Failing to account for these data quality issues in realtime may mask drilling dysfunction causing accelerated damage to the drill bit and drilling assembly. This paper also aims to highlight techniques for displaying and interpreting drilling data to enhance drilling performance as well as diagnose dysfunction during reviews of historic wells. Understanding these limitations in advance and incorporating them in a team's surveillance strategy can help with the diagnosis of drilling dysfunction and aid performance improvement.

These recommended practices have been developed to offer a foundation for drilling surveillance, interpretation and monitoring as well as training for the industry. They have been created such that they can grow organically and may be used for developing subsequent industry publications.

The work described in this paper is part of a joint International Association of Drilling Contactors (IADC) / Society of Petroleum Engineers (SPE) industry effort to revise the IADC dull grade process.
Wettability Alteration of Kerogen by Interacting with Hydraulic Fracturing Fluid
Authors: Yi Xuan , Lee Kyung Jae
Published: September 2022

The recent increase in unconventional oil and gas exploration and production has promoted active research on hydraulic fracturing, but the impact of interactions between fracturing fluid and kerogen on the alteration of kerogen wettability has not been well understood. The objective of this study is to experimentally estimate the changing wettability of kerogen with various thermal maturity levels by the interactions with hydraulic fracturing fluid.

To achieve the objective, kerogen was isolated from a bulk rock of organic-rich shale with different types and maturities. Kerogen isolates was kept in a mix with synthetic hydraulic fracturing fluid under the temperature of 80 °C for 14 days. Relative changes of sulfate ions were analyzed by using Ion Chromatography (IC). In the measurement of kerogen wettability, sessile drop method was applied to measure the direct contact angle by utilizing the Drop Shape Analyzer (DSA). During the reaction with hydraulic fracturing fluid, kerogen isolates were analyzed by conducting functional group analysis, which provided the supplemental information on the wettability of kerogen. Functional groups of kerogen were analyzed by using the Attenuated Total Reflectance Fourier-Transform Infrared spectroscopy (ATR-FTIR).

The reaction of fracturing fluid and kerogen isolates from various organic-rich shales were conducted, and it is experimentally demonstrated that the interactions between kerogen and fracturing fluid would cause substantial wettability alterations in organic pores and fractures that depend on the types and maturities of kerogen. The DSA results indicated that the air/water-contact angle decreases after the reaction, regardless of the types and maturities of kerogen, while the higher level of maturity of kerogen led to a greater change of air/water-contact angle. The results of ATR-FTIR showed that the hydrophobic functional groups were lost in the mature kerogen isolates, and they were potentially lost in the relatively lower level of maturity-kerogen isolates due to the oxidation, indicating that the kerogen showed increasing hydrophilicity, which provided a strong support to the DSA results.

This study experimentally determined the wettability alteration of kerogen by interacting with organic additives in hydraulic fracturing fluid. The results of this investigation will provide a significant step forward in evaluating the multiphase fluid transport in organic-rich shales with the wettability alteration and resulting hydrocarbon production.
A Practical Approach to Model Four-Phase Flow Through Porous Media
Authors: Gong Xu , Fang Chen , Li Zhidong , MacIsaac Gordon , Motahhari Hamed Reza
Published: September 2022

The recent advancements in the field trial of the solvent-based Enhanced Oil Recovery methods indicate the presence and simultaneous flow of four phases (i.e. water, vapor, heavy liquid hydrocarbon and light liquid hydrocarbons) in the hydrocarbon reservoirs. The accurate modeling of these field observations is not achievable in the most commercial reservoir simulators as they are generally formulated for three phase equilibrium and flow calculations. This paper evaluates the merits of a newly proposed approach [1] to incorporate an algorithm to model the four-phase flow within the conventional three-phase reservoir simulation framework without need for major change in formulation or code revamp.

Compositional data from field pilot trial of the Cyclic Solvent Process (CSP) is used to evaluate the simulation model capabilities to model flow of four-phases in the porous media. The reservoir simulation models are used to history match the production performance of CSP process in in the field. Laboratory and field CSP data indicate the presence and flow of 4 phases in different stages of the CSP production cycle.

The previously proposed "phase-combination" approach shows limited capability to match the changes in the compositional assay of the produced hydrocarbons in CSP process. In this paper, an improved "Coflow" formulation is proposed based on the modified Einstein Equation for dispersed flow. The new formulation is implemented in conventional three-phase reservoir simulation framework and tested against the data providing superior capability in match in the field production assay data.

This paper provides a practical method to model four phase flow within the framework of the three phase reservoir simulation frameworks. The newly proposed "coflow" method in combination with the previously developed method provides a consistent framework to model flow of two hydrocarbon liquid phases in the porous media either in a continuous or dispersed flow patterns. This enables use of commercially available reservoir simulator for modeling of solvent-based EOR methods without need to significant changes in formulation or code revamp.
Effective Water Treatment in the Permian and Marcellus Shales to Mitigate Surface Equipment Failures
Authors: Kakadjian Sarkis , Korhonen Keith , Solomon Marvin , Kitchen Jarrett , Gebrekirstos Amanuel , Risner Jesse , Algadi Otman
Published: September 2022

Chemical and oxidative biocides are designed to sanitize water by reducing aerobic and anaerobic bacterial populations in the fresh, brackish and reclaimed source waters. These biocides are used extensively in high-rate fracture stimulations to reduce formation damage, chemical degradation, biogenic H2S and microbial induced corrosion (MIC). Oxidative biocides work by removing electrons from the cell wall of aerobic and anaerobic bacteria. The same electron transfer mechanism can be detrimental to surface equipment. This study presents the impact of several oxidative biocides on the corrosion rate and pitting of different frac iron alloys and how those biocides effect the mechanical integrity of elastomer seals. It also presents different remediation methods to mitigate their oxidative effects.

The oxidative biocides tested were Chlorine, Chlorine Dioxide and a Peracidic Acid blend. The corrosion rate of the iron alloys coupons was measured by weight loss analysis. This method can measure the rate of corrosion in pounds per square foot at time and was used to compare the impact of different residual oxidizers on the corrosion rate of the ground iron. Structural changes to the elastomers were detected visually.

The results of the study showed that the corrosion rate varied depending on the alloy/residual oxidative biocide combination. Usually, Peracidic Acid blend or Chlorine had the highest corrosion rates across all alloys tested; depending on the oxidative biocide/alloy combination, the corrosion rate could vary by a factor of 2X over the nine-week timeframe. Elastomer testing over 6 weeks showed variability in the types of structural changes depending on the concentration and oxidative biocide tested.

The lab and field testing included onsite monitoring of the corrosion rate, oxidation reduction potential (ORP), oxygen in solution and determination of the Langelier Saturation Index (LSI). The methodology has been effective in predicting iron failures related to the composition of the water and/or presence of oxidizers. Chemical solutions implemented to mitigate the surface iron failures included use of intermittent blends of water-soluble quaternary amines and surfactants. Since these remediation attempts have started, the replacement cost of frac iron has decreased from over 550K US$ per month, per frac spread to none, over a 3-month period.
A Simple and Practical Approach to Estimate Dispersive Mixing in Underground Hydrogen Storage Systems
Authors: Maniglio Marco , Pizzolato Alberto , Panfili Paola , Cominelli Alberto
Published: September 2022

Hydrogen represents a strategic vector to compensate for seasonal energy production/demand discrepancies, deriving from the rapid increase in renewables resources needed to achieve the 2050-net-zero emissions target. Subsurface porous rocks, like depleted gas reservoirs, are a promising solution to store the hydrogen volumes to accomplish those targets. The efficiency of Underground Hydrogen Storage (UHS) systems can be largely affected by the mixing between hydrogen and the original gas due to mechanical dispersion at different scales.

A methodology was developed to evaluate the loss of hydrogen in storage operations which can be ascribed to diffusive/dispersive phenomena. Results suggest that large-scale heterogeneity dispersive transport is the dominant factor affecting the hydrogen storage efficiency when compared to molecular diffusion, core-scale dispersion and, depending on the grid resolution, numerical diffusion. Moreover, reservoir-scale heterogeneities have far greater impact on hydrogen dispersivity than pore-scale heterogeneities, questioning the usefulness of experimental campaigns on reservoir rock samples.

The study provides a simple workflow to quickly estimate the impact of dispersion induced by large-scale heterogeneities on UHS efficiency. Results are of prompt practical interest for pilot applications as the methodology can be applied on real assets, considering the scale and storage strategy of interest.
Wellbore Integrity Impact on Carbon Leakage to Ensure Safe Geological Sequestration
Authors: Ning Yanrui , Tura Ali
Published: September 2022

Secure and safe geological sequestration is critical for the successful deployment of carbon capture and storage (CCS) projects and to mitigate global warming. Oil/gas reservoirs and saline aquifers, that are suitable for CO2 sequestration, often have older pre-existing wells near the potential CO2 injection wells. The legacy producing and abandoned wells have the potential to behave as CO2 leakage pathways, despite the existence of a good seal formation or structural certainty. In this study, this poorly understood and largely unknown leakage potential is researched to quantify the carbon leakage rate along one legacy well when carbon is injected into a storage formation in the Denver-Julesburg (DJ) Basin. This study investigates the risk of containment loss for a leaky well using a one-square-mile section of the DJ Basin. The results show that the completion of an older wellbore has a significant effect on the leakage rate results. A small portion (10-8) of the injected carbon can leak via a multi-segmented wellbore, while around 2.5% CO2 can leak to the drinking water layer via an open wellbore. Our results indicate that for secure carbon sequestration, a good geological storage site should be kept away from wells that have a surface casing depth of 476 ft or shallower and were drilled before 1994 in Colorado. The effective well permeability highly impacts the leakage rate, implying the importance of estimating the most representative value/range for this parameter. This risk assessment research is a part of the pre-feasibility study to support potential large-scale geological carbon storage operations in Colorado.
Biomineralization: A Natural Solution to Eliminate Gas Migration
Authors: Hiebert Randy , Panzo Lauren , Hyatt Robert
Published: September 2022

A Seneca Resources Company, LLC (Seneca) natural gas well in Pennsylvania was leaking methane from both the 13-3/8 in × 9-5/8 in (55 psi) and the 9-5/8 in × 7 in (85 psi) cemented annuli. Previous attempts to mitigate the problem had proven unsuccessful, which prompted the trial of a new method using the natural process of biomineralization.

BioSqueeze Inc. (BSI) was contracted by Seneca to apply their proprietary biomineralization technology to the well. To prepare the well, circumferential notches were cut through all casing strings all the way to the formation to allow fluid injection into the annuli. Biomineralizing fluids were then pumped into the well, where they formed crystalline calcium carbonate in the micro annuli.

After 1.5 days of treatment, the injection rate dropped by several orders of magnitude. Subsequent monitoring by a state regulator determined surface pressure had been eliminated and there were no escaping hydrocarbons.
Mechanically-Robust Nanocellulose Engineered Preformed-Particle-Gel for Conformance Control in Fractured Tight Reservoirs: Transport Through Proppant-Packed Porous Media
Authors: Wei Bing , Mao Runxue , Tian Qingtao , Lei Wenhai , Tang Jinyu , Wang Dianlin , Lu Jun
Published: September 2022

Preformed-particle-gel (PPG) holds promising potential for conformance control in fractured tight reservoirs because it enables mitigation of fracture channeling with insignificant leakoff. However, conventional PPG with weak and brittle network is severely vulnerable to shrinkage, breakage, fatigue and even degradation during extruding through narrow fractures that were much smaller than themselves, and finally results in the failure of gel treatment. Therefore, in this work, a new kind of nanocellulose-regulated robust particle-gel (N-PPG) was designed and prepared using high-modulus and green nanocellulose (NCF). The mechanical properties of N-PPG including hardness, springiness, resilience, chewiness and cohesiveness were assessed using a texture analyzer at the grain-scale. The results demonstrated that the presence of NCF (0.1 wt%) noticeably improved the mechanical properties of PPG, 49.5% increment of hardness, 29.3% of resilience, 86.3% of chewiness and 25% of cohesiveness. The swelling test showed that the salinity had slight effect on the swelling kinetics and equilibrium swelling ratio (SR) of N-PPG. N-PPG exhibited excellent tolerance to the acidic solution. After aging for 44 days, SR fluctuated slightly and maintained at 9 cm3/g. The gel skeleton was not collapsed, and the microstructure was similar to the control group (aged in the neutral solution). Upon transporting through the fractures, the porous media was packed using millimetric-sized glass beads to replicate proppant-filled fractures after hydraulic fracturing. N-PPG exhibited significantly higher resistance factor (Fr) and residual resistance factor (Frr), indicative of better performance in conformance control. The influence of particle size, velocity, and PPG elasticity on the transport and placement of PPG in fractures were investigated. Due to the preeminent mechanical properties, N-PPG was hardly broken even after being extruded out from pore-throat geometries with up to a particle-throat diameter ratio (Dg/Dp) of 15, whereas the control PPG was notably crushed, implying the low efficiency in deep applications of conformance control. The Fr of PPG in fractures analogously depended on Dg/Dp even if the superficial velocity (u) was varied from 0.72 m/d to 4.32 m/d. To fully consider the interaction between deformable particle and fluid in the complex pore-throat geometries, an Immersed Boundary-Lattice Boltzmann modeling (IB-LBM) was developed to numerically simulate PPG passing through a throat (50 μm). A spring-network model was used to capture the deformation of PPG. The grain-scale modeling yielded the pressure profile of PPG, from which a clog-deform-pass procession mode was defined.
Technology Screening & Selection for Site Specific, Adaptive and Cost Effective MMV Planning & Design
Authors: Das Debasis Priyadarshan , Tiwari Pankaj Kumar , Patil Parimal Arjun , Chidambaram Prasanna , Jordan Leite Renato , Ebinining Amir M Syafeeq , Tewari Raj Deo , Baharuddin Salina , A Hamid M Khaidhir
Published: September 2022

Carbon Capture & Storage (CCS) has globally been recognized as the way forward to manage & reduce Green House Gas (GHG) emissions. However, for every geological CO2 storage project there are two inherent yet independent storage risks: loss of containment and loss of conformance. For early detection and mitigation of these risks, a robust Monitoring, Measurement and Verification (MMV) plan is of supreme importance. While several matured, newly developed and under trial monitoring technologies addressing various aspects of MMV are currently available but it's crucial to evaluate them in terms of applicability, durability, ease of operation & maintenance, and cost to the project. This study focuses on the screening and selection monitoring technologies to achieve a site-specific, adaptive, and cost-effective MMV plan and design.

Identification of critical containment & conformance risks were achieved through integrating information from various elements viz. CO2 plume migration forward modeling, 3-way coupled modeling, well integrity analysis, overburden risk analysis, CO2 marine dispersion modeling, environmental impact assessment (EIA), regulatory requirements, etc. Based on identified risks, the specific MMV elements were selected along with designing of their scheduling and frequency. Subsequently, an inventory of all available technologies addressing explicit MMV needs was prepared. These technologies were put through rigorous analysis on their capability of detection, operability, tool/technology longevity, availability, and associated costs. High-ranking technologies were then knitted for the final MMV planning & design.

As a part of the arduous screening, permanent ocean bottom (OB) monitoring technologies were analyzed and some of the alternate low-cost technologies surfaced that can cater to continuous and long- term data acquisition needs. Knitting of 3D Distributed Acoustic Sensor – Vertical Seismic Profile (DAS- VSP) hybrid with 3D seismic surveys would help optimizing the logistic requirements and reducing cost of monitoring survey acquisition over the project lifecycle. During the entire screening and selection process, Multi-Fiber Optic Sensor System (M-FOSS) technology emerged as the leading monitoring technology, which is cost-effective, easy to operate and has the flexibility to be deployed at well and/or on seabed. An exhaustive inventory of available/emerging MMV technologies and the cost versus benefit matrix was developed that can be used for MMV planning and design across CCS projects. The study focuses to streamline the long-term sustainability of the adapted MMV planning to enhance the project economics by ensuring the optimum value propositions of implemented technologies.
Best Practices in DFIT Interpretation - Comparative Analysis of 83 DFITs in the Canadian Duvernay Shale Play
Authors: Virues Claudio , Robertson Alexandra , AbouKhalil Emile
Published: September 2022

In September 2021, the Alberta Energy Regulator (AER) through a new pressure and deliverability testing directive issued new guidance for minifrac tests, also known as diagnostic fracture injection tests, to align with the current practice for conducting these tests. This paper statistically summarizes results from 83 of these DFITs, submitted by many operators from the Canadian Duvernay shale play. The main parameters analyzed were closure, reservoir pressure and permeability.

This newly updated directive sets out requirements for pressure and deliverability tests. In the development of tight or unconventional reservoirs, industry moved towards horizontal wells with multistage fracture treatments using a minifrac (also referred to as DFIT or diagnostic fracture injection test), which became the more common well test in determining closure, initial reservoir pressure and permeability. In this paper, a comparison of holistic vs compliance methods descriptions for closure pressure are provided. Complete governing equations for after closure analysis methods are described in detail to permit readers to replicate all results on reservoir pressure and permeability.

For closure pressure, the compliance model is compared to the holistic model that is published or commercially available. Comparisons are also provided for After Closure Analysis (ACA) models including the Soliman and Nolte methods as far as reservoir pressure and permeability are concerned. 83 field case studies are presented for horizontal wells in an unconventional shale play. The most significant findings are 1) a compliance closure pressure signature is not apparent in the analyzed DFITs, 2) closure pressure estimates, and outcomes are similar for the compliance and holistic methods 3) reservoir pressure determination differentiation using either linear or radial flow 4) PVT impact on interpretation and 5) order of magnitude difference for permeability determination on After Closure Analysis methods. The findings have direct practical implications for operators in the Canadian Duvernay shale play and analogous shale plays in USA and elsewhere. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and fracture design. Accurate closure pressure is fundamental to hydraulic fracture design and other geomechanics applications. Accurate initial reservoir pressure is important because it could be used for input for Rate Transient Analysis (RTA) for resources / reserves assessments in similar unconventional plays.

The novelty of the comparative analysis is in the ability to show in unconventional shale plays how closure pressure methods compared, and the implications of using different after closure analysis methods which could be of significant benefit to a practicing engineer or well testing interpreter
Innovative Applications of Oil Soluble Tracers in Unstimulated & Stimulated Multi-Stage Horizontal Wells for Long Term Flow Assurance and Production Monitoring
Authors: Ramanathan Venky , Mombourquette Cole , Martinez Alberto , Borschneck Sean
Published: September 2022

Sliding sleeves have been an integral part of horizontal multistage completions, however intelligent sleeves that provide reservoir insights were missing or cost prohibitive. This led to the innovative development of integrating oil soluble tracer applications with sleeve technology to provide superior completions and reservoir diagnostics. Conceived to validate flow in unstimulated wells / stages, the longevity and value of the data collected led to extending this application for long term flow assurance monitoring of unstimulated and stimulated wells.

Spinner based production logging techniques require intervention and have limited capability in wells with artificial lift. Tracer sleeve integration requires zero intervention and builds on the back of proven tracer diagnostics, and field proven sleeve technologies. A winning combination for production operation optimization.

The monitoring feature is especially useful in wells that are put on production prior to stimulation. These applications effectively allow for flow assurance and production profiling between unstimulated and stimulated traced stages. Fluid samples are collected at surface for a period of several months, over which time trend fluctuations in tracer concentrations are monitored and evaluated.

Reservoir intelligence that production engineers can act on is now available at their fingertips. With more than two-hundred-fifty (250) installations on multiple wells during the first year of application, tracer sleeves have become part of the standard operating process. Results obtained over a multitude of study wells have indicated that tracer sleeve technology provides effective monitoring of both the relative flow contribution, and flow assurance of each traced stage for the subject wells. Studied wells were monitored for periods no shorter than three (3) months following initial production, and in most cases continued to display detectable readings from tracer sleeves well over nine (9) months. This has also led to lower intervention costs and limiting the number of interventions to wells that show unsatisfactory tracer concentrations. In conclusion this diagnostic approach has provided validation and insight for wells or regions of a lateral where previously, flow contribution and productivity were assumed.

The introduction of oil soluble tracers into production sleeve technology has allowed for short- and long-term diagnostics (flow assurance and production monitoring) of hydrocarbon contribution in unstimulated and stimulated regions of horizontal multi-stage wells in a hybrid completion. A superior diagnostic solution where cost prohibitive or intervention options were the only available alternative.
Iron Sulfide Scale Inhibition Through Adsorption of Chelating Agents
Authors: Gasimli Nijat , Mahmoud Mohamed , Hassan Amjed , Shahzad Kamal Muhammed , Patil Shirish , Al-Abdrabalnabi Ridha
Published: September 2022

An important oilfield issue is the formation of a wide range of scales during oil and gas well operations. Oilfield scales hinder assessing an optimum hydrocarbon production as their precipitation on formation, various surface, and downhole equipment leads to many problems, including pressure decrement, formation damage, and operational failure of subsurface equipment. One type of these scales is the iron sulfide scale and based on studies in the Khuff reservoir, iron sulfide scales are likely to deposit on production tubing and rock formation. Therefore, it becomes essential to restrain the occurrence of iron sulfide scale using environmentally friendly chemicals in production tubing, water injection wells, and near-wellbore formation.

The primary focus of this work is the prevention of iron sulfide scale deposition in carbonate formations during water injection applications. Iron sulfide scale inhibition was studied through dynamic inhibition adsorption experiments. In contrast to conventional experiments, for scale inhibition and adsorption of chelating agents (static bottle, dynamic filter tube tests) and simulation studies, a novel experimental setup (coreflooding experiments) was proposed to study the inhibitor adsorption. Broad concentrations of high-pH aminocarboxylic acids (such as ethylenediaminetetraacetic acid (ETDA) and diethylenetriamine pentaacetate acid (DTPA)) were examined (10 wt%, 15 wt%, and 20 wt%), at temperatures of 120°F and 200°F.

Results of the study revealed that iron (III) precipitation is an obvious threat causing severe formation damage in carbonate rocks by significantly decreasing the rock permeability. Adsorption of chelating agents on limestone rocks highly depends on their concentrations. Specifically, an increase in the concentration of EDTA and DTPA at elevated temperature conditions resulted in higher adsorption. The inhibition experiments revealed that 20 wt% EDTA could significantly decrease the iron sulfide scale precipitation.

Unlike the conventional testing methods for scale formation and prevention, a novel experimental setup - coreflooding during the inhibitor adsorption, formation, and inhibition of iron sulfide scale in carbonate formation was used. The main advantage of the method is the consideration of permeability alteration happening due to the scale formation. Another point is that in previous studies, various scale control chemicals and experimental approaches have been suggested for iron sulfide scale inhibition, and polymeric, phosphonate, and sulfonated co-polymeric inhibitors were used. However, the subgroup of chelating agents - aminocarboxylic acids, was used in this study.
Online Flow Assurance Tool for Optimum Wax Management at Field
Authors: Bhaskoro Petrus Tri , Anuar Astriyana , Rasib Amira A , Wollebaek Lars , Rezvany-Hesary Farnaz , Lutro Henrik , Henriksson Johan , Sariman Mior Zaiga , Shafian Siti Rohaida M , Torres Carlos Francisco
Published: September 2022

Traditionally, a field's wax management and operating philosophy have been developed by conducting a rigorous Flow Assurance (FA) study. Optimization at field level warrants the study to be updated from time to time to reflect the actual field performance. This accounts for overall field performance but does not incorporate variations due to operational changes. Rather, the operating philosophy is based on representative scenarios where conservative measures are often used to safeguard operations. With the increasing number of waxy crude oil pipelines within company that demands immediate attention, an online prediction/monitoring tool that quickly adapts to operational changes is one important enabler, not only to optimize operations and address the huge Operating Expenses (OPEX), but also to address remote/unmanned operation's requirement especially for subsea operation. Unfortunately, to date, such a tool is not commercially available or deployed widely. To address this gap, this paper aims to present the Online Wax Smart Meter development concept and to showcase the performance of an online wax monitoring tool which enables fast and optimum wax management.
Novel Dual Completion Architecture Improves Oil Production and Boosts Secondary Recovery with Minimal Surface Footprint
Authors: Leon Fernando , Silva Angel , Villalobos Jorge Luis , Guerrero Ximena , Amores David , Villarreal Alejandro , Cuenca Dario , Cuenca Diego , Jaramillo Dorian , Corella Byron , Perez Mauricio
Published: September 2022

The novel dual electric submersible pump (ESP) completion was designed to maximize oil recovery by improving waterflooding efficiencies while minimizing capital expenditures (capex) and surface facilities. The design enables the operator to produce oil and formation water from the same well. The injection of water, produced from the same oil producer, is part of a waterflooding project to boost secondary recovery.

Based on the dual concentric completion (DCC) concept, this novel solution integrates an inverted flow architecture to provide the upper ESP with direct access to the lower reservoir zone, which is the water-producing zone. This single ESP is then used as the only equipment to lift the produced water and then provide sufficient pressure for direct injection into a neighboring well, without the need for surface treating and handling facilities. Oil production is lifted by the encapsulated lower ESP. The complete solution includes a monobore anchor with an automatic release tool to eliminate oil-zone damage during the completion phase and maximize water-zone productivity.

The upper reservoir expected to produce approximately 700 BOPD with 1% water cut; after the successful implementation and commissioning of this novel architecture and its impact on the secondary recovery process, the recorded production reached more than 1,000 BOPD, with an overall 35% oil production increase in the field.

Using a monobore anchor with an automatic release tool to perforate the lower sand allowed to combine the underbalance technique with clean perforations system and high impact penetration charges, which resulted in greater water zone productivity and improved pump efficiency, reducing power consumption by 33%. Considering that the project was implemented with a local diesel generator, the total CO2 emissions reduction was approximately 700 metric tons per year in just one well.

Because the novel inverted DCC solution does not require the construction of traditional surface facilities for water injection, which include horizontal pumping systems (HPSs), capex was significantly reduced. In addition, because this solution was developed, designed, and implemented in far less time than a traditional method would have been, production was increased earlier than otherwise possible, helping the operator meet production targets and increase cash flow.
An Integrated Method to Mitigate Hazards from Hydraulic Fracturing-Induced Earthquakes in the Duvernay Shale Play
Authors: Hui Gang , Gu Fei , Chen Zhangxin
Published: September 2022

In recent decades, a remarkable increase in induced seismicity in the Western Canada Sedimentary Basin (WCSB) has been largely attributed to the hydraulic fracturing (HF) operations in unconventional plays. However, a mitigation strategy concerning geological, geomechanical, and operational susceptibilities to HF-induced seismicity has not been well understood. In this work, an integrated method is proposed to mitigate potential risks from HF-induced seismicity in the Duvernay play near Crooked Lake. The geological susceptibility to induced seismicity is evaluated first from site-specific formation pressure, a distance to the Precambrian Basement, and the existence of pre-existing faults. The regional in-situ stress and rock mechanics are then assessed to determine the geomechanical susceptibility to induced seismicity. Next, the operational susceptibility is determined by comparing induced seismicity with operational parameters such as total injection fluids and proppant mass. Finally, a multiple linear regression (MLR)-based approach is proposed by considering the feature importance of different parameters. It is found that regions with a low formation pressure (<60MPa), a great distance to the Precambrian Basement (>260m), a low minimum principal stress (<70MPa), and a low brittleness index (<0.62) tend to be seismicity-quiescent regions. Three new horizontal wells are drilled and fractured to validate the applicability of our MLR-based approach. High-resolution monitoring results indicated that 95% of the induced events had a magnitude of less than 2.0 during and after HF operations (three-month time window and five-kilometer well-event distance), among which the maximum magnitude reached M3.05 (<red light magnitude M4.0). Therefore, the MLR-based approach was successful in mitigating potential seismicity risks, which can be applied to other regions to guide seismicity-free fracturing operations in unconventional plays.
Microwave-Assisted Catalytic Heating for Enhanced Clean Hydrogen Generation from Methane Cracking in Shale Rocks
Authors: Yan Keju , Yuan Qingwang , Jie Xiangyu , Li Xiaoqiang , Horita Juske , Stephens Jacob
Published: September 2022

Steam methane reforming (SMR) technology generates about 95% hydrogen (H2) in the United States using natural gas as a main feedstock. While hydrogen is clean, the process of hydrogen generation via SMR is not, as it emits about 10 times more carbon dioxide (CO2) than hydrogen. The CO2 has to be captured and sequestrated in reservoirs or aquifer systems, which is costly. A revolutionary approach is to generate and extract hydrogen directly from petroleum reservoirs by taking advantage of the abundant unrecovered hydrocarbons in reservoirs. This approach does not involve natural gas production, transportation, or refinery. Meanwhile, the CO2, if generated, will be sequestrated simultaneously in reservoirs without being produced to surface. This approach is therefore potentially low cost and environmentally friendly. In this paper, we propose to use microwave-assisted catalytic heating to enhance methane conversion to hydrogen within shale gas reservoirs. To validate this concept, we conducted a series of experiments to crack methane streams flowing through shale rock samples and powders in a microwave reactor. With silicon carbide (SiC) as the microwave receptor, the temperature of shale samples can quickly reach to above 700 °. The methane conversion efficiency is up to 40.5% and 100% in the presence of Fe and Fe3O4 catalysts at the measured temperature of 500° and 600 °, respectively. Interestingly, the presence of shale is favorable for methane cracking at a relatively lower temperature compared to the case with the same weight percentage of SiO2 in heated samples. The thermal decomposition of carbonate in shale rocks also benefits the improvement of permeability of shale. The influences of different shale weight ratios and methane flow rates are also investigated.
Overall Enhanced Surveillance and Production Delivery Strategy: The Backbone of Oil Production Sustainability at Country Level in Malaysia
Authors: Bakar Hasmizah , Mohd Khalid Ruzanna , Idris Khairul Nizam , Borhan Nor Aisyah , Masoudi Rahim , Abu Bakar Mohamad
Published: September 2022

While the world is still reeling from the unprecedented challenges brought on by the pandemic, the energy sector remains focused on business continuity standpoint. It is a big challenge for Enhanced Value Optimization (EVO) taskforce, as appointed focused group in PETRONAS Malaysia Petroleum Management (MPM) to monitor and assure national production target delivery for all hydrocarbon resources in Malaysia. The focus was devotedinto oil fields in Malaysia. As regulator, it is crucial to quickly act to implement and adjust regulations & steers to meet new demands for safe operations during global pandemic. Several work streams have been lined upwith specific goals and indicators to manage the upside potentials and risks for late life reservoirs, well integrity issues, new oil project, unplanned deferments, production enhancement and idle wells reactivation activities. Through regular engagements with operators, Opportunities and Threats (O&T) are collectively registered and tracked in monthly Malaysia oil production conversation to generate short-term and long-term additional potentials and trigger any constraints to base production in advanced. This paper will also discuss on the limitation of resources, operational window, Malaysian government enforcement for isolation & quarantine during pandemic high time, widespread budget reprioritization, probability of success for execution of activities to realized opportunities and mitigation plans to mitigate threats from both sides, regulator and operators. In improving production performance conversations with operators, EVO Command Centre leverages on PETRONAS UP Mobile Application and UP Web with desired solution and integration from various data reporting dashboard as communication for quick business decision platform. The value of EVO as special taskforce in MPM for more just a reporting medium comes through intensification of efforts and proactive management of overall oil assets to realize business production target. The authors would also like to share their experienceas devoted Shapers and Enablers to safeguard Malaysia production target that may inspire other petroleum authorities in transforming the ambition(s) into action.
Novel Completion to Manage Crossflow in a Newly Completed Openhole Gravelpack Gas Well. A Case Study From the Norwegian Continental Shelf
Authors: Hewitt Neal , Tay Boon Li , Rincon Alexander , Ringe Thomas
Published: September 2022

An openhole gravelpack (OHGP) gas well was planned as part of an infill drilling campaign on a mature Norwegian Continental Shelf field. A geological pilot hole unexpectedly identified a significant pressure differential between two reservoir intervals. This paper describes an innovative modification of the lower completion, within a short turnaround time, in order to manage the clean-up of the reservoir intervals and limit crossflow.

Calculations based on the pilot hole results predicted that the low pressure reservoir would not flow until there was significant depletion in the high pressure reservoir. This risked formation damage due to delayed clean-up. Additionally, there was potential for very high crossflow rates that risked mechanical damage to lower completion equipment and/or causing formation damage.

There was insufficient time to completely redesign the completion. A solution, supported by simulations, showed that a fixed choke in the lower completion would enable immediate clean-up of both reservoir intervals. Additionally, aplug had to be set in the gravel-filled annulus to prevent flow diverting around the fixed choke. These modifications would reduce the potential crossflow rate to an acceptable level.

The OHGP was performed as originally planned. A wireline tool was run to inject an epoxy resin plug into the gravel and the fixed choke was then set at the same depth. The well was cleaned up as planned to the drilling rig, with both reservoir intervals observed to be producing.

The choke toolstring included an additional flow area that automatically opened after a pre-defined time delay. Simulations predicted the pressure differential at this time to be significantly lower. Reducing the choking effect in this way, once the risks from crossflow at the start of well life had been minimised, avoided hindering production in later well life.

The well has performed as expected with no indications of production impairment having occurred, despite the initial period of high differential pressure between the reservoir intervals.

This is believed to be the first injection of epoxy resin into a newly completed gravelpack. Coupled with the implementation of the two-sized choke it has been possible to manage a problematic reservoir pressure differential in a new well without resorting to costly and lengthy redesign of the completion.
A Knowledge-Based Artificial Intelligence Approach to Risk Management
Authors: Canon Javier , Broussard Theresa , Johnson Andrew , Singletary Will , Colmenares-Diaz Lolymar
Published: September 2022

This paper details experiences gained while developing a novel technology-driven approach to Risk Assessment methodologies, e.g., Process Hazard Analysis (PHA), Hazard Identification (HAZID) and Hazard Operability (HAZOP), in oil & gas. Emphasis has been placed on combining encoded human knowledge with Artificial Intelligence techniques, in a way which fosters safer designs and operations, while maintaining Subject Matter Experts (SMEs) at the center of decision making.

Encoding of human knowledge (e.g., Subject Matter Expertise, Industry best practices) in digital applications has traditionally been associated with creating static pieces of information, such as lessons learned documentation and validation activities for hazard analysis. New digital technologies, however, make it possible to create truly dynamic knowledge representations, which capture key concepts and their relationships, creating a new type of "source of truth." As a result, corporate and external knowledge can be made more readily accessible to engineers and operations personnel participating in decision making.

Digital corporate knowledge can also be supplemented with Artificial Intelligence (AI) techniques which can help uncover latent threats and better guide optimal decision making. This is particularly relevant in Workforce, Health & Safety (WH&S) and Process Safety contexts, where the impact of flawed or suboptimal decisions can lead to catastrophic consequences.

Practical examples from an oil & gas major show how the risk assessment domain can be represented in a computational knowledge graph, in a format which is comprehensible not only to software developers, but more importantly, to oil & gas SMEs. A presentation of different AI techniques overlaid on top of this computational knowledge graph, can also offer a glimpse of the possibilities of marrying SME expertise with emerging digital technologies.