bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Digital Well Construction Planning Tool During Well Conceptualization Phase
Authors: Hugo Costeno , Rajeswary Kandasamy , Jose Telles , Jacob Camacho , Diego Medina , Freddy Gori , Hector Garcia , Omar Vilchez
Published: September 2021

Digital well construction tools are becoming more widely considered today for well design planning, enabling automated engineering and simultaneous team collaboration under a single solution. This paper shows the results of using a digital well construction planning solution during a project’s conceptual planning stage. This method shortens the time needed to estimate the well times and risk profile for a drilling campaign by applying smart engines to quickly and accurately perform critical offset analysis for defined well types that is required for project sanction.

With this solution, the Offset Well Analysis (OWA) process is done automatically based on the location of the planned well, trajectory and well architecture. Various information and reports (both subsurface and surface data) from neighboring wells is stored in cloud solutions, enabling ease of access and data reliability for both large or smaller scale data storage. The software selects the most relevant offset wells, displays the risk analysis and generates the stick chart. For a conceptual design, the risk levels can be manually set higher due to potential unknowns in surface and subsurface risks which can later be refined. Quick validation of the well design allows the engineer to design a conceptual drilling campaign quickly and more efficiently.

The solution minimizes the time to perform probabilistic time and risk estimations. It reduces the risk of biased decision making due to manual input and design. This allows for better-informed decisions on project feasibility, alignment of stakeholders, increased design reliability as well as reducing the amount of time and resources invested in OWA.

The work presented here is aimed at sharing the experience of applying a digital well construction planning solution specifically on the conceptual project stage and discuss the value it adds to the well design process.
Development of a Digital Twin for Well Integrity Management in Underground Gas Storage Fields
Authors: Busollo Carlo , Mauro Stefano , Nesci Andrea , Scimmi Leonardo Sabatino , Baronio Emanuele
Published: September 2021

Objective

Digitalization is offering several chances to improve performance and reliability of Underground Gas Storage (UGS) infrastructures, especially in those sites where ageing would require investment improvement for maintenance and monitoring. In that context, well integrity management can benefit from the implementation of a well digital twin, integrated with real time monitoring.

The work proposes a digital model of the well that can provide a valuable tool to analyse its non stationary states in order to evaluate the integrity of the barriers and its health state.

Methods, Procedures, Process

The key points on well integrity management are barriers testing/qualification and annular pressure monitoring, and in UGS operations it’s crucial the selection of the timing of barrier assessment and of diagnostic test execution to correctly evaluates the results.

The digital model can provide a tool to help the well engineer to understand the health state of the well and to plan maintenance activities. It considers a physical model of the well composed by gas and liquid filled chambers in the annuluses and in the tubing case and all the potential leak paths that could connect the annuluses, the tubing case, and the reservoir to the external environment.

Each chamber is modelled considering its mass and energy balance, while fluid resistances describe fluid leakage across the barriers. Appropriate models, selected according to the geometry and type of each well barrier, describe each fluid resistance.

The input parameters are the well architecture, flowing tubing temperature and pressure and gas flow rate. The model provides pressure and temperatures trends and estimates of leak rates trends or annular liquid level movements during the observation time window.

The fine tuning of the model of each well is carried out by seeking for the values of the parameters that best describe each single leak path, such as size and position of the leaking point, with a genetic algorithm.

Results, Observations, Conclusions

The model has been customised and validated over several wells, some of which with perfect integrity status and others with some integrity issues. Results showed a very good fit with field data, as well as high precision in identifying leak position and size.

The tool can also be applied to forecast well behaviour after the application of mitigating action or to simulate the evolution of the leak. Example applications are the evaluation of the correct time to top up a casing with liquid or nitrogen or the effect on annular pressure of limiting withdrawal or injection flow rate.
Ultralow Concentration of Amphiphilic Molybdenum Disulfide Nanosheets for Enhanced Oil Recovery-Research and Field Application
Authors: Qu Ming , Liang Tuo , Hou Jirui , Wu Weipeng , Wen Yuchen , Xiao Lixiao
Published: September 2021

Recently, spherical nanoparticles have been studied to enhance oil recovery (EOR) worldwide due to their remarkable properties. However, there is a lack of studies of nanosheets on EOR. In this work, we synthesize the amphiphilic molybdenum disulfide nanosheets through a straightforward hydrothermal method. The octadecyl amine (ODA) molecules were grafted onto the surfaces of molybdenum disulfide nanosheets due to the presence of active sites over the surfaces of MoS2 nanosheets. The synthesized amphiphilic molybdenum disulfide nanosheets (ODA-MoS2 nanosheets) are approximate 67 nm in width and 1.4 nm in thickness. The effects of ultralow concentration ODA-MoS2 nanosheets on the dynamic wettability change of solid surfaces and emulsion stability were also studied and discussed. Besides, the core flooding experiments were also conducted to reveal the adsorption rules and the oil displacement effects of ultralow concentration ODA-MoS2 nanosheets. Experimental results indicate that the oil-wet solid surface (a contact angle of 130°) can transform into the neutral-wet solid surface (a contact angle of 90°) within 120 hrs after 50 mg/L ODA-MoS2 nanosheets treatment. In addition, micro-scale emulsions in size of 2 µm can be formed after the addition of ODA-MoS2 nanosheets by adsorbing onto the oil-water interfaces. The desorption energy of a single ODA-MoS2 nanosheet from the oil-water interface to the bulk phase is proposed. When the concentration of ODA-MoS2 nanosheets is 50 mg/L, the emulsions are the most stable. Core flooding results demonstrate that the ultimate residue of ODA-MoS2 nanosheets in porous media is less than 11%, and the highest increased oil recovery of around 16.26% is achieved. Finally, the production performance of ultralow concentration of ODA-MoS2 nanofluid (50 mg/L) in the application of Daqing Oilfield is summarized and discussed.
Ultrasonic Slowness Images for Geological Interpretation: Investigating Field Test Examples of a New LWD Technology
Authors: Shrivastava Chandramani , Blyth Matthew , Sakiyama Naoki , Yamamoto Hiroaki , Haecker Adam
Published: September 2021

Borehole images have long been used for various applications related to geological interpretation, geomechanics and well-placement objectives. Based on the physical measurement used, the resolution and detection limit of the image logs vary considerably thereby limiting or enhancing the applications envelope against specific objectives. A new logging-while-drilling (LWD) technology of pitch-catch (PC) ultrasonic is under development, that can also provide borehole images of compressional and shear slowness in anisotropic and / or heterogenous formations both in water and oil-based-mud. Geological application of these images (which have inch-scale resolution) is being assessed and investigated with respect to the already established ultrasonic pulse-echo (PE) LWD images. While PE images show details of the borehole wall and are thus subject to the effects of drilling practices, the PC images reflect the rock mechanical properties of the formation at the depth of investigation of the measurement, in the same fashion as density images.

Two case-studies are presented to assess the quality and application of these images; with one vertical and one horizontal well. The PC images are shown to provide a lot of meaningful information in addition to PE images, though the PC images lose out on detailed information related to texture and subtle structural features. In fact, the gross geological features of bedding and some sedimentation sequences have been imaged with confidence, with manifestation of the features available across the entire azimuthal coverage with the new-technology images and confident dips with sinusoidal fits are picked for gross geological variations. The horizontal well PC images have picked up higher confidence low-angled features than the vertical well PC images due to the longer intersection with borehole wall. The slowness images are found to provide confident bed-boundaries, also some fracture-traces are visible only on the slowness images. However, major vertical fractures and drilling-induced fractures (DIF) are more prominent on the PE amplitude images. The results show that slowness images offer the capability to understand gross structural dip and facies variability at a better resolution than conventional LWD images of similar resolution, and with the benefit of not needing to utilize a chemical source in the drilling bottom-hole assembly (BHA) for density images. Although the slowness measurements azimuthally have been developed to investigate near wellbore geomechanical concerns, such as stress, heterogeneity, and anisotropy, it is clear that the resultant images also have geological applications that is demonstrated by the datasets shown. These applications mean that the images could offer a more sustainable geosteering capability if delivered in real-time.
Development and Evaluation of a New Electrical Submersible Pump for High Viscosity Environments
Authors: Matheus Laura , Anaya Oscar , Izquierdo Sebastián , Garzón Miguel , Lee Woon
Published: September 2021

Conventional methods of Heavy Oil production have either delivered low recovery factors or have involved costly thermal projects. With low oil prices the new norm, Operators need to maximize their recovery factors whilst controlling CAPEX required to exploit their assets. This paper presents a new approach to lifting heavy/viscous oil with a Pump design that will allow Operators to increase overall field production with reduced energy consumption.

A trial was conducted in Colombia in a harsh field (high viscosity, low water cut, high temperature and high gas production) that had challenged conventional artificial lift systems as Electrical submersible pumps and progressive cavity pumps. Several strategies (light oil injection, high capacity equipment, solvents injection at surface) had been implemented to overcome fluid viscosities 6,000 cP @ 150 °F at dead oil conditions and a mean of 250 cp inside the pump, with excellent short and medium-term results but system hydraulic efficiency and energy consumption were still below expectations.

A new pump has been specially designed for the fluid conditions previously described, with the main objective of reduce the friction losses inside the pump stage increasing the overall efficiency and reducing energy consumption. Initial trial results have fulfilled the study's objectives, overcoming the issues previously experienced with ESP operations in this field.

Designed to handle heavy, high viscosity oil, this study has demonstrated that there is significant economic benefit through savings and improved efficiencies and, in addition, ESP capital cost savings. Previously, oversized units were routinely used to deliver the required flow and pump power but by optimizing the sizing of the ESP system, it is possible to select pumps with fewer stages and lower horsepower motors to suit the new requirements.

Data from the field tests have delivered encouraging results. The pump has operated smoothly since installation and, in comparison to standard pump, has reduced energy consumption (savings of 10-15%) and shown a 15-20% increase in pump efficiency. The Operator has reasonable optimistic expectations for future installations in this field in all applicable wells.
It's Not the End of Petroleum Engineering
Authors: Meehan D. Nathan
Published: September 2021

Is this the end of petroleum engineering as we know it? This prescient question led to the most downloaded paper from onepetro.org in 2019. The events of 2020 resulted in massive layoffs, decreased hiring and many fewer students studying petroleum engineering. In the 2019 paper the authors claimed that the future would hold fewer petroleum engineering jobs and very different types of jobs. This paper incorporates a broader range of data and proposes some specific ways to improve prospects for the discipline of petroleum engineering.

The opportunity for a near-term recovery is very high as the world overcomes COVID-19 issues, oil demand recovers and the impact of chronic underinvestment in oil and gas production looms. The world's largest producers have very different abilities to respond to a near-term uptick in demand. Energy transition pressures continue to cap growth in demand; however, demand for petroleum engineers is expected to grow under almost every scenario, but not to pre-2015 levels. Increased demand in CCUS and jobs that improve sustainability of oil and gas will continue to outpace conventional jobs. Data analytics will play an increasingly large role in engineering activities.

The "Is it the end?" paper started with a question, a question that I first heard asked in 1977 at the SPE Annual Fall Technical Conference and Exhibition in Denver to 1972 SPE President M. Scott Kraemer. I have heard it many times since then and asked it many times. "Would you recommend that your son or daughter study petroleum engineering?" The answer to that question was pretty easy and unanimously positive in 1977. Keep this question in mind as we review what has happened since the prior paper came out.
The True Market Value of a Good Petroleum Engineer: A Technical Perspective
Authors: Michael Andreas
Published: September 2021

Defined by SPE as the application of basic and engineering sciences to the finding, development, and recovery of oil, gas and other resources from wells, petroleum engineering (PE) has been throughout the years falsely thought of as an amalgamation of other disciplines applied to the exploration and recovery of hydrocarbons. Integrating all PE subdisciplines in a manner efficient for teaching and learning is essential for securing the abundance of well-rounded market-attractive professionals. This paper discusses advantages individuals with PE background experience should exhibit in their employment in the oil and gas industry and academia. There is no point for students in going to school for a degree that will not hand them a competitive edge within their discipline.

For graduate PEs, the job market is dependent on the quality of their respective academic programs and by extension to the quality of the teaching faculty. A steady oil and gas job market may not necessarily warrant robust employment opportunities, particularly straight after graduation. In a discipline like PE, where almost everything that matters takes place thousands of feet underground, apportioning credit for successes or responsibility for failures is itself a challenge. Decreases in student enrollments in PE programs reported by various universities during times of low oil and gas prices poses questions about the future of the PEs discipline, despite the steady demand for oil and gas in the world's energy mix. Academic programs interested in facilitating a smooth transition of their graduates into the industry should work in conjunction with practitioners to provide the correct balance between theory and practice in their coursework ensuring that once employment opportunities are created, they get filled with candidates of relevant education and training.

PE degree-holding candidates should be the natural first choice for PE positions. This means that their educational and professional backgrounds should be providing them with an undisputed advantage which places them a leg above candidates from other disciplines. For instance, for a well completions job opening, there should not be a better alternative than a good PE specialized in well completions. If every PE graduate comes out of his or her program with a skillset which is superior to that of his or her competition, he or she will be the preferred choice for an oil and gas job.
Application of Dynamic Risk Management Approach To Mitigate Major Accidents
Authors: Onazi Adai
Published: September 2021

As industries continue to grow, complexities and uncertainties associated with process systems tend to increase, and so are the potential major industrial accidents with corresponding catastrophic consequences. To combat these industrial accidents around the worldwide, there is a need for a more dynamic approach to hazard identification and risk management that proactively mitigates potential exposures in real-time. Evidence suggests that a dynamic approach to risk management can identify and assess developing and increasing industry risks and prevent unwanted outcome. The Piper Alpha investigation and the derivation and adoption of safety case framework in the UK is a proven approach to mitigate major accident hazards for the front-end design of high-risk process facilities, throughout their lifespan. With the increasing complexity of process systems, dynamic risk management as a next-generation risk management approach is required to ensure operational safety. This study aims to stimulate discussions on the novel dynamic risk management approach, leveraging advanced technologies such as artificial intelligence and the 4th Industrial Revolution as a new risk management pathway for industrial accident prevention.
PACT - One Step Closer to Well Control Autonomy
Authors: Petersen Christian , Strand Ola , Johansen Espen , Hansen Dag Almar , Fredheim Dag Ketil , Ohlckers Per
Published: September 2021

Pressure control have been going through steps of evolution. In the highlight of safety, reliability and control, the systems have been sturdy withstanding massive pressure and environmental impact to last the time of estimated life of well. Design have been emphasizing on sturdiness rather than intelligence and autonomy. Time moves on, sophistication levels rise in all parts of our industry. Sustainability and lower environmental impact of solutions grow from the young into business planning and democratic policies. Control lines of hydraulic systems posed risks to the environment as well as being costly in structure and maintenance. Condition monitoring helped ensure better maintenance planning and lowered the risk of breakdown, but still left a lot to be desired reaching for self-contained, self learning systems with low installation and maintenance costs, yet the safest approach.

The next steps were taken towards electrification and digitization of pressure control systems, making short and undetermined strides over almost two decades. Still, the standards are not following the pace of technological progress. And when someone dares to pilot or demonstrate modern technology applied, the installations and operational procedures of the systems still need expensive distributed lines of power, of signals and control systems to ensure a swift and safe operation. The fly-by-wire principle applied in oil & gas is the operate-by-costly-technology-and-environmental-impact-lines.

With the introduction of new and breaking technology in energy harvesting and storage, the playing field opens up towards fully automated systems with no need for expensive power lines or hydraulic control lines. The safety will be taken care of also off-grid, fully digitized. Should cabling of instrument signals be damaged, the system of tomorrow will still be up to par with the Safety Integrity Levels needed. New super-capacitors with an extra dense storage capacity being developed in partnership between the industry and the University of southeast Norway combined with an extremely low energy consuming actuation system with the fastest failsafe mechanism ever will ensure safety in all modes of operation, even with all lines down or consumed by flames. The paper aims to show how the technology works and underline why it will take a place in the future of well control and production.
Successfully Optimizing Breakers in Polyacrylamides for Slickwater and High-Viscosity Fluids
Authors: Kakadjian Sarkis , Kitchen Jarrett , Flowers Amanda , Vu John , Gebrekirstos Amanuel , Algadi Otman
Published: September 2021

Polyacrylamide-based friction reducers (FR's) - including viscosifying polyacrylamides, which are designed to decrease proppant settling by increasing molecular weight and/or active material in the FR - are used extensively in high-rate fracture stimulations. However, because polyacrylamides are difficult to break, there have been concerns about how these materials impact fracture conductivity and formation permeability. This study presents the effect of conventional and novel oxidative breakers over the viscosity and colloidal size distribution of the broken polymers.

Breakers tested include conventional persulfates, perborates and patent pending peroxides, all of which generate free radicals to degrade partially hydrolyzed polyacrylamides (PHPAs). Breakers were tested at bottomhole temperatures encountered in the Permian, Bakken, Haynesville and Eagle Ford. Changes to PHPA viscosity were determined using vibrational viscometers. Size distributions and percentage of the broken colloidal PHPA were determined by dynamic light scattering. This method can measure sizes down to 0.6 nanometers, which is within the range of even the smallest pore-throat sizes in shales.

Light scattering revealed surprising anomalies in breaker performance. When aged at temperatures typical of the Permian, each of the tested breakers at each of the varied concentrations caused similar levels of viscosity reduction but different size distributions. Some breakers had the unwanted effect of narrowing the colloidal size fractions to the lower end of the spectrum. At these small sizes, colloids are more likely to overlap with segments of the pore throat distribution in some shales, which could inhibit production. In addition, when the FR was aged at the higher temperatures encountered in the Bakken, Eagle Ford and Haynesville, some breakers were not able to uniformly break the PHPA. In these cases, FR's without breakers delivered superior performance. The results clearly demonstrate that breakers may not always have the desired effect of increasing the formation's permeability. In fact, depending on the type of breaker and the concentration, they can often have detrimental effects that ultimately hinder production.
Blue Hydrogen Economy - A New Look at an Old Idea
Authors: Ehlig-Economides Christine , Hatzignatiou Dimitrios G.
Published: September 2021

Previous efforts to promote hydrogen as an energy carrier described a Utopian world in which renewable resources provided all energy for heating, electricity, transportation, and industrial needs. The elegance of this vision overlooked the cost and the footprint represented by the renewable energy resources required to generate so much electricity, and the additional cost required to employ electrolysis to generate hydrogen for energy storage not possible for electricity. Today an abundance of natural gas offers an option for hydrogen generation from methane that can include capturing and storing CO2 produced from the generation process. This results in blue hydrogen, effectively as ecologically attractive as the green hydrogen from electrolysis, and considerably less expensive. This paper evaluates a New Hydrogen Economy employing blue hydrogen as a bridge to net zero greenhouse gas emissions.

Of particular interest is the observation that depleted natural gas reservoirs offer pore space sufficient to store about 1.5 times the CO2 coming from hydrogen generation from the produced natural gas. The implication of this observation is that blue hydrogen generation need not rely on saline aquifer storage or on CO2 Enhanced Oil Recovery. We find that blue hydrogen cost is comparable to the cost of current crude oil-based transportation fuels. Further, electricity generated using blue hydrogen is less expensive than decarbonized electricity generated from natural gas with post combustion CO2 capture and storage. The infrastructure required for this energy transition can leverage existing natural gas transport and storage and existing petroleum industry skills.

Energy companies committed to net zero emissions need not rely only on renewable energy sources or nuclear power. Further, switching to blue hydrogen reduces or eliminates combustion related pollution including nitrogen and sulfur oxides. Finally, the Blue Hydrogen Economy makes efficient and cost effective use of petroleum engineering core skills, as well as the core skills championed by the petroleum industry.
Countrywide Integrated Capacity Model – Enabling Production Planning and Performance Management Leveraging Big Data and Digitization of Engineering Workflows
Authors: Al Selaiti Iman , Mabrook Maged , Hoda Mohammad Faizul , Saputelli Luigi , Hafez Hafez , Mohan Richard , Pires Joshua , Asarpota Jyotsna , Hernandez Cristina
Published: September 2021

Production planning and performance management imply diverse challenges, mainly when dealing at corporate level in an integrated operating company. Production forecast considers technical capacities, available capacities, and operationally agreed target capacities. Such complex process may hinder taking advantage of market opportunities at the right time. Proactive scenario management and information visibility across the organization are key for success.

This paper intends to share the lessons learned while rolling out a countrywide integrated capacity model solution supporting corporate production planning and performance management. The rollout processes aimed at digitizing the monthly and yearly production forecasting. In addition, these processes shall enable formulating proactive scenarios for avoiding shortfalls, maximizing gas throughput, production ramp up, and minimizing operating cost from existing capacity.

Abu Dhabi's Integrated Capacity Model is an integrated production planning and optimization system relying on a large-scale subsurface-to-surface integrated asset model system; in this paper, we focus on the incremental progress of the challenges derived from the various rollout efforts. The rollout of such a complex solution relies on basic tenets for managing the change across a large organization.

The first tactic is about continuous stakeholder engagement through value demonstration and capabilities building. Engagement is achieved by continuously providing information about proactive shortfall and opportunity identification within the installed asset capacity. Monthly asset reviews provide the basis for user interaction and initiate the basis for establishing ad-hoc production maximization scenarios. Establishing a data governance and performance metrics were also key for embedding the solution in the business processes.

The solution delivers tangible and intangible value. From the tangible point of view, it contributes to production efficiency gains by compensating during specific proactively identified shortfalls and after-the-fact events. As a result, our solution has been instrumental in deriving cost reduction scenarios and profitability gains due to optimum GOR management. In addition, the system use has reported various intangible gains in terms of better data utilization, enhanced corporate database quality and reduced overall human load in managing production capacity.

The solution described in the paper implements a simpler way the production planning and performance management at corporate level in a large integrated operating company. The in-house developed tool and its implementation is a novel approach in terms of integration, complexity, and practical application to the fields in Abu Dhabi.
Closed Looped Production Rate Evaluation by Means of Virtual Metering and Pressure Transient Analysis
Authors: Ursini Fabrizio , Frau Simone Andrea , D'Addato Francesco , Romice Luigi , Furlani Sergio , Vignati Emanuele , Trevisan Matteo , Montini Marco
Published: September 2021

The Integration of real-time high frequency data in well models allows to infer useful information regarding well and field performance. Virtual Metering (VM) algorithms aim at providing real time well rates solving an inverse problem based on flow equation in the wellbore. Although VM methodologies are based on Pressure/Temperature measurements, they rely on availability of calibration measurements. Pressure Transient Analysis (PTA) can provide useful insight for VM calibration.

An innovative closed-loop workflow combining VM and PTA has been developed to face unreliable or absent rate measurements. VM requires periodical separator tests for model calibration. PTA played an important role in estimating well production rates, using it as a virtual well test to compensate the lack of field tests. VM rates are used as first guess for the PTA interpretation of build-up where production rates are unreliable. PTA log-log derivative plot is compared with the reference one which was interpreted to calibrate the formation K•H. The loop is iterated correcting VM calibration parameters until the match is acceptable.

An implementation of the closed loop rate estimation workflow on an offshore oil asset is presented as an application of the methodology. The asset comprises 15 production wells, most of them with high Gas-Oil Ratio. Virtual Metering has been applied on wells fully equipped with wellhead and bottom-hole sensors. The joint application of PTA with an iterative closed loop philosophy was fundamental to compensate the lack of separator tests and of the sometimes unreliable choke opening data. The accuracy of the production profiles simulated by the VM is confirmed by the comparison with the reference asset fiscal production and by the final pressure history matching obtained with the PTA. The application of the iterative closed-loop workflow plays a fundamental role in the improvement of backallocation, in real time production monitoring and in the implementation of production optimization. Well models based on VM algorithm have been included in production optimization workflow to improve the well line-up and identify production optimization opportunities. Virtual Metering allowed to monitor results of optimization actions by estimating the actual wells production increment.

This paper contains a novel approach, consisting in a reliable and robust closed loop virtual metering workflow, which integrates different tools with the common objective of assessing the actual well production rates for maximising the asset performance. The real-time data and model sharing allowed to set-up a collaborative environment optimizing effective problem solving and field production performance.
A Novel Gemini Cationic Viscoelastic Surfactant-Based Fluid for High Temperature Well Stimulation Applications
Authors: Friesen Dawn , Seymour Brian , Sanders Aaron
Published: September 2021

Viscoelastic surfactant (VES)-based fracturing fluids can reduce the risk of formation damage when compared with conventional polymer-based fracturing systems. However, many VES systems lose viscoelasticity rapidly under high-temperature conditions, leading to high fluid leakoff and problems in proppant placement. A gemini cationic VES-based system offering thermal stability above 250°F and its efficiency in friction reduction is presented in this paper.

Rheology measurements were conducted on viscoelastic cationic gemini surfactant fluids as a function of temperature (70 – 300°F) and surfactant concentration. The length of surfactant alkyl chain was varied to investigate the impact of surfactant chain length on VES fluid viscosity at elevated temperatures. The effect of flow rate on friction reduction capability of the surfactant fluid was measured on a friction flow loop. Foam rheology measurements were conducted to evaluate the VES fluid's ability to maintain high temperature viscosity with reduced surfactant concentration.

A gemini cationic surfactant was used to prepare a viscoelastic surfactant system that could maintain viscosity over 50 cP at a shear rate of 100 s−1up to at least 250°F. With this system, viscoelastic gel viscosity was maintained without degradation for over 18 hours at 250°F, and the fluid showed rapid shear recovery throughout. Decreasing the average alkyl chain length on the surfactant reduced the maximum working temperature of the resulting viscoelastic gel and showed the critical influence of surfactant structure on the resulting fluid performance. The presence of elongated, worm-like micelles in the fluid provided polymer-like friction reduction even at low surfactant concentrations, with friction reduction of over 70% observed during pumping (relative to fresh water) up to a critical Reynolds number. Energized fluids could also be formulated with the gemini surfactant to give foam fluids suitable for hydraulic fracturing or wellbore cleanouts. The resulting viscoelastic surfactant foams had viscosities over 50 cP up to at least 300°F with both nitrogen and carbon dioxide as the gas phase.

The information presented in this paper is important for various field applications where thermal stability of the treatment fluid is essential. This will hopefully expand the use of VES-based systems as an alternative to conventional polymer systems in oilfield applications where a less damaging viscosified fluid system is required.
Accurate Multi-Phase Flow Simulation in Faulted Reservoirs Using Mimetic Finite Difference Methods on Polyhedral Cells
Authors: Dong Rencheng , Alpak Faruk O. , Wheeler Mary F.
Published: September 2021

Faulted reservoirs are commonly modeled by corner-point grids. Since the two-point flux approximation (TPFA) method is not consistent on non-orthogonal grids, multi-phase flow simulation using TPFA on corner-point grids may have significant discretization errors if grids are not K-orthogonal. To improve the simulation accuracy, we developed a novel method where the faults are modeled by polyhedral cells, and mimetic finite difference (MFD) methods are used to solve flow equations. We use a cut-cell approach to build the mesh for faulted reservoirs. A regular orthogonal grid is first constructed,and then fault planes are added by dividing cells at fault planes. Most cells remain orthogonal while irregular non-orthogonal polyhedral cells can be formed with multiple cell divisions. We investigated three spatial discretization methods for solving the pressure equation on general polyhedral grids, including the TPFA, MFD and TPFA-MFD hybrid methods. In the TPFA-MFD hybrid method, the MFD method is only applied to part of the domain while the TPFA method is applied to rest of the domain.

We compared flux accuracy between TPFA and MFD methods by solving a single-phase flow problem. The reference solution is obtained on a rectangular grid while the same problem is solved by TPFA and MFD methods on a grid with distorted cells near a fault. Fluxes computed using TPFA exhibit larger errors in the vicinity of the fault while fluxes computed using MFD are still as accurate as the reference solution. We also compared saturation accuracy of two-phase (oil and water) flow in faulted reservoirs when the pressure equation is solved by different discretization methods. Compared with the reference saturation solution, saturation exhibits non-physical errors near the fault when pressure equation is solved by the TPFA method. Since the MFD method yields accurate fluxes over general polyhedral grids, the resulting saturation solutions match the reference saturation solutions with an enhanced accuracy when the pressure equation is solved by the MFD method. Based on the results of our simulation studies, the accuracy of the TPFA-MFD hybrid method is very close to the accuracy of the MFD method while the TPFA-MFD hybrid method is computationally cheaper than the MFD method.
Integrated Rock and Fluid Workflow to Optimize Geomodeling and History Matching
Authors: Ruiz Elizabeth , Thibodeaux Brandon , Dorion Christopher , Mukisa Herman , Faskhoodi Majid , Hakim Bilal , Garcia German , Xu Wayne , Betancourt Soraya , Canas Jesus , Messonnier Tom , Mullins Oliver
Published: September 2021

Optimized geomodeling and history matching of production data is presented by utilizing an integrated rock and fluid workflow. Facies identification is performed by use of image logs and other geological information. In addition, image logs are used to help define structural geodynamic processes that occurred in the reservoir. Methods of reservoir fluid geodynamics are used to assess the extent of fluid compositional equilibrium, especially the asphaltenes, and thereby the extent of connectivity in these facies. Geochemical determinations are shown to be consistent with measurements of compositional thermodynamic equilibrium. The ability to develop the geo-scenario of the reservoir, the coherent evolution of rock and contained fluids in the reservoir over geologic time, improves the robustness of the geomodel. In particular, the sequence of oil charge, compositional equilibrium, fault block throw, and primary biogenic gas charge are established in this middle Pliocene reservoir with implications for production, field extension,and local basin exploration. History matching of production data prove the accuracy of the geomodel; nevertheless, refinements to the geomodel and improved history matching were obtained by expanded deterministic property estimation from wireline log and other data. Theearly connection of fluid data, both thermodynamic and geochemical, with relevant facies andtheir properties determination enables a more facile method to incorporate this data into the geomodel. Logging data from future wells in the field can be imported into the geomodel allowingdeterministic optimization of this model long after production has commenced. While each reservoir is unique with its own idiosyncrasies, the workflow presented here is generally applicable to all reservoirs and always improves reservoir understanding.
Toward Controllable Infill Completions Using Frac-Driven Interactions FDI Data
Authors: Cai Yuzhe , Dahi Taleghani Arash
Published: September 2021

Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.
Stability of Chemically Degraded Friction Reducers and Their Relationship to Regain Conductivity
Authors: Ayazi Philip , Monreal Gabriel , Bleibel Hassan , Zamora Frank , Watters Larry
Published: September 2021

Previously, it was shown that zeta potential could be used as a metric to determine friction reducer (FR) performance. Specifically, the extent of and how quickly the FR reaches peak friction reduction in source water. A correlation postulated from the previous work is zeta potentials relationship to an FR's stability during mechanical or chemical degradation. In other words, can zeta potential be used as a metric to determine the extent of polymer breaking and can this relationship be translated to regained conductivity? This paper describes a laboratory study of zeta potential measurements to track breaker reaction rates, stability of broken polymer dispersions, and the relationship between chemical degradation of FRs and regained conductivity.

The approach of this investigation involves measuring zeta potential of frac fluids formulated using anionic and cationic FRs with varying types and concentrations of breakers at different temperatures and times. These metrics are then correlated with regain conductivity. A quantitative relationship exists between zeta potential, fluid rheology, and regain conductivity. Zeta potential evaluation of degraded FR's in frac fluids correlate to performance in regain conductivity testing. These measurements can expedite the selection of chemical breakers with respect to performance. Zeta potential measurements of degraded FR are indicative of broken FR dispersion stability which has impact on regain conductivity. Tracking behavior of cationic FR's using zeta potential reveals the materials can become anionic with time and temperature and become susceptible to agglomeration with iron. Zeta potential measurements can be used during a chemical breaker selection process as a viable supplement to industry standard tests for assessing the comparative effectiveness of chemical breakers in frac fluids.
Complex Subsurface Well Abandonments Using Relief Well Methodologies
Authors: Dorey Jamie , Rassadkin Georgy , Ridgway Douglas
Published: September 2021

The field experience in the continental US suggests that approximately 33% of plug and abandonment operations are non-routine, and 5% require re-entry (Greer C.R., 2018). In some scenarios, the most cost-efficient option for the intervention is drilling an intercept well to re-enter the target well or multiple wells externally using advanced survey management and magnetic ranging techniques. This paper presents the methods applied of relief well methodologies from the planning to execution of a complex multiple-well abandonment project.

Improvements in Active Magnetic Ranging sensor design and applications have improved the availability of highly precise tools for the purpose of locating and intercepting wellbores where access is not possible. These instruments were commonplace on relief well interventions, however, have found a new application in solving one of the major issues facing the oil and gas industry. Subsurface abandonments are a complex task that requires a robust methodology. In this paper, we describe the techniques that have been built upon the best practices from industry experience (ISCWSA WISC eBook). This paper also illustrates how the combination of advanced survey management, gyro surveying, and magnetic ranging can be used following the best industry practices for fast and cost-efficient non-routine plug and abandonment.

Case studies of several abandonment projects are presented showing the various technical challenges which are common on idle and legacy wells. The projects include wells that are currently under the ownership of an operator and orphaned wells that have been insufficiently abandoned and left idle over many decades. The case studies outline how the application of relief well methodologies to the execution of complex sub surface interventions led to the successful outcomes of meeting environmental and government regulations for wellbore abandonment. This includes performing multiple zonal isolations between reservoirs, water zones and preventing oil and gas seepage to the surface. The projects and their outcomes prove economically viable strategies for tackling the growing issue of idle and orphaned wells globally in a fiscally responsible manner.

Combining industry best practice methods for relief well drilling, along with the technological advancements in magnetic ranging systems is a solution for one of the largest dilemmas facing the oil and gas industry in relation to idle and orphaned wellbores. These applications allow previously considered impossible abandonments to be completed with a high probability of long-term success in permanent abandonment.
Efficient Modeling of Depletion Induced Fracture Deformation in Unconventional Reservoirs
Authors: Pei Yanli , Sepehrnoori Kamy
Published: September 2021

The change of fracture conductivity during reservoir depletion significantly affects the well performance and stress evolution in unconventional formations. A common practice is to model fracture deformation using the traditional finite element method with very dense unstructured grids representing complex fracture geometries. However, the associated computational cost is high, so previous studies mainly use empirical correlations to catch the fracture conductivity loss or neglect fracture deformation during the production period. This work proposes a novel coupled flow and geomechanics model with embedded fracture methods to capture the fracture deformation accurately yet efficiently in unconventional reservoirs. Under a single set of structured grids, an embedded discrete fracture model (EDFM) is employed to characterize fluid flow through discrete fractures by introducing non-neighboring connections, and an extended finite element method (XFEM) is applied to simulate discontinuities over fracture walls by adding phantom nodes. In addition, a modified proppant model is incorporated to represent interactions between proppants and hydraulic surfaces, and an iterative coupling scheme is implemented to link the fracture-related fluid flow and solid mechanics. Being validated against the classical benchmark problem, the coupled model is used to investigate the impacts of proppant strength, closure stress, and bottomhole pressure on fracture deformation, well production, and in-situ stresses. Numerical results indicate that weaker proppant support induces more fracture aperture and production losses, resulting in greater stress changes and higher residual pressure in the depletion region. In comparison, the fracture deformation for a well-propped scenario is modest and barely affects the well performance and stress redistribution. Less stressed formation corresponds to lower closure stress on fracture walls, which triggers limited fracture closure and stabilizes well production. Moreover, a moderate bottomhole pressure decline rate avoids significant fracture closure while preserves relatively high initial production rates. The coupled flow and geomechanics model with embedded fracture methods resolves computational difficulties in modeling complex fracture deformations and delivers more insights on production forecast and stress changes crucial to refracturing and infill operations.