bluuebunny/crossref_metadata_2025 huggingface dataset:
Impact of Injection Water Quality on Injectivity – A Lab Study
Authors: Karazincir Oya , Gomez-Nava Sandra , Evans Paul , Wu Ruiting , Williams Wade , Jones Colin , Rijken Peggy
Published: September 2019

Waterflooding is commonly performed in oil wells for pressure support and increased oil production. Different sources of injection water can be used for waterflooding, such as aquifer water, seawater or produced water. Each of these water sources contain particulates in them that deposit at the injection point forming both an external filter cake on the reservoir face and an internal cake inside the rock surface. The properties of the external and internal filter cake negatively affect injectivity. In order to identify the optimum water filtration specs prior to injection, the contribution of different solid particle types present in the injected water on filter cake properties and injectivity need to be understood.

A lab study has been undertaken to gauge the contribution of different solid types, solid sizes, and the presence of oil droplets on filter cake properties and water injectivity. The solid types tested were silica/quartz, clay, iron oxide, barium sulfate and calcium carbonate, with and without oil contamination. Membrane tests were conducted to understand the correlation between the porosity and the permeability of the external filter cake that forms at the formation face for each particulate type. A heavy slurry of selected solid particulate was mixed in brine and was compressed into a membrane under different applied pressures, and the porosity and the permeability of the cake was calculated at each stage. Core tests were designed to look at the combined effects of the external and internal filter cake on reduction in injectivity. Outcrop cores, representative of the field cores, with similar pore throat size, porosity and permeability were used in the core tests, as particle bridging at pore throats is a function of the comparison between the injected particle size and the pore throat size distribution of the reservoir. A slurry of the selected solid particulates in brine was injected into the core system and the permeability drop across the core was monitored as a function of injected water pore volumes. Both types of tests were repeated in the presence of oil contamination in the injected water. The test data from the membrane tests and the core tests were used in the numerical model to obtain the permeability reduction function for the internal and external filter cake.
Long-Term Productivity Comparison of Gel and Water Fracture Stimulation in Marcellus Shale Play
Authors: Al-Alwani Mustafa A. , Britt Larry K. , Dunn-Norman Shari , Alkinani Husam H. , Al-Hameedi Abo Taleb , Al-Attar Atheer M.
Published: September 2019

The goal of any hydraulic fracturing stimulation is to design and execute the appropriate treatment that is best suited for the stimulated reservoir. Selecting the best treatment must achieve the desired fracture geometry to maximize long-term well productivity and reserve recovery. The main objective of this study is to conduct detailed short and long-term production and well-to-well comparisons of the different types of fracture stimulation fluids in the Marcellus Shale play.

A database of more than 4,000 horizontal, stimulated Marcellus wells was constructed for this study. The wells were divided into four groups according to the type of treating fluid: water, gel, cross-linked, and hybrid fracs. Chemical data from FracFocus were gathered and processed then combined with completion and production data to investigate the gas short and long-term production. Detailed monthly production data for the studied wells were captured from DrillingInfo database and utilized in this study.

This paper reports and compares the Marcellus gas initial production, the gas cumulative production at the end of the first month, first 6 months, first year, 2 years, and 5 years, according to the type of hydraulic fracturing fluid used in primary stimulation. The work provides insights into Marcellus well performance as a function of stimulation parameters such as the volume of stimulation fluid and the amount of pumped proppants. The impact of perforated lateral length is taken into consideration and used to normalize production and stimulation parameters. The study shows that water fracturing fluids outperformed the other types of hydraulic fracturing fluids.

This paper introduces several data processing workflows that serve as a reference for individuals who are interested in extracting and processing data from the FracFocus database. It also documents the occurrence in hydraulic fracturing fluid types and measures the effects of the fracturing fluid volume and total proppant pumped on the initial and cumulative production.
Analytical Models for Interpretation and Analysis of Transient Sandface and Wellbore Temperature Data
Authors: Onur Mustafa , Galvao Mauricio , Bircan Davut Erdem , Carvalho Marcio , Barreto Abelardo
Published: September 2019

The objectives of this study are to (i) provide analytical transient coupled wellbore/reservoir model to interpret/analyze transient temperature drawdown/buildup data acquired at both the producing horizon (sandface) and a gauge depth above the producing horizon (wellbore) and (ii) delineate the information content of both transient sandface and wellbore temperature measurements. The analytical models consider flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system and provide temperature-transient data for drawdown and buildup tests produced at constant rate at any gauge location along the wellbore including the sandface. The production in the wellbore is assumed to be from inside the production casing. The models account for Joule-Thomson (J-T), adiabatic fluid-expansion, conduction and convection effects as well as nearby wellbore damage effects. The well/reservoir system considered is a fully penetrating vertical well in a two-zone radial composite reservoir system. The inner zone may represent a damaged (skin) zone, and the outer (non-skin) zone represents an infinitely extended reservoir. The analytical solutions for the sandface transient temperatures are obtained by solving the decoupled isothermal (pressure) diffusivity and temperature differential equations for the inner and outer zones with the Boltzmann transformation, and the coupled wellbore differential equation is solved by Laplace transformation. The developed solution compares well with the results of a rigorous thermal numerical simulator and determines the information content of the sandface and wellbore temperature data including skin zone effects. The analytical models can be used as forward models for estimating the parameters of interest by nonlinear regression built on any gradient-based estimation method such as the maximum likelihood estimation (MLE).
Tradespace Exploration for Offshore O&G Developments - A Model Based Systems Engineering Approach
Authors: Leocadio da Nova Anderson
Published: September 2019

The objective of this paper is to explore the benefits of using the Interactive Epoch-Era Analysis (IEEA) methodology for evaluating architectural changes in a trade space exploration study. In this paper a subsea tieback offshore Brazil will be used as reference case to investigate this premise from a full field development perspective.

An automated concept exploration tool is employed. It applies meta-heuristics to generate different offshore facilities concepts with varying building blocks. The interaction between reservoir behavior and facilities design is accounted for, meaning pressure and temperature losses throughout the system are taken into account in each concept differently. These concepts are ranked in terms of economic performance indicators (NPV, IRR, etc.), and each run with a given set of boundary conditions covers what is called an Epoch. This process is iterated for the whole life of field with a set of different boundary conditions, such as commercial aspects ($/bbl, $/MMBtu, market demand) and/or technological maturity aspects (TRL, novel technological concepts), generating what is called an Era. The whole data set is then evaluated in an interactive platform thru the Humans-In-the-Loop (HIL) process.

Model Based Systems Engineering (MBSE) is being employed successfully in other engineering fields outside the O&G context such as the aerospace and automotive industries. While digital tools have been identified as a potential key contributor to the future of O&G performance enhancement and further cost reductions, that is yet to be shown. This work intends to provide backing for that argument in one of the potential applications during early concept exploration phases by showing that quick high value assessments following an MBSE approach may be carried out, once significant effort has been put into proper development, verification and validation (V&V) of such digital tools.

While integrated models for asset development have long been a subject of interest for O&G operators, the application of Systems Engineering concepts to it has not yet been thoroughly explored. Systems Engineering provides a rigorous and proven method of dealing with complex systems that is highly applicable to offshore field developments. MBSE is the current State of the Art for capital intensive projects such as space exploration spacecrafts and rovers. Learning from these successful use cases and applying these methodologies in the development of digital technologies may provide a new set of tools in the belt of O&G operators Facilities Engineers and alike. The study case presented shows MBSE’s capability of capturing intrinsic non-linearities and specificities of each O&G field/location while ensuring project wide functional requirements are successfully met.
Characterization and Modeling of the Fault Network of a Brazilian Pre-Salt Reservoir and Upscaling Results
Authors: De Lima Alexandre , Fourno André , Noetinger Benoit , Schiozer Denis José
Published: September 2019

Carbonate Brazilian pre-salt fields have a large number of faults detected by seismic and well data. Nevertheless, because of limitations in seismic resolution, all existent faults cannot be identified. That is one of the main challenges for understanding related heterogeneities (vugs, karst) and the flow behavior. This paper deals with a fault analysis and modeling using an original approach and fault data of three pre-salt reservoirs.

One possible approach for characterizing and modeling the fault network (Verscheure et al, 2010) aims the integration of all available conceptual knowledge and quantitative data. This sub-seismic model keeps the geological consistency of seismic faults through capturing its specific spatial organization. First, geometry of seismic faults was characterized based on fractal methods. Secondly, sub-seismic faults were generated with stochastic algorithm. The work originality is also related to the studied reservoir which is close to two other fractured reservoirs. Each one aims a fault network with a specific fractal dimension. The fractal dimension choice was discussed.

The results presented on this article lead us to discuss the importance of how to choose the samples for modeling sub-seismic faults based on the ensemble of seismic faults available. This article answers the question about which available seismic faults we should use for estimating fractal dimension, should we use all available seismic faults near of the reservoir area or use only the faults inside the reservoir contour. After this short discussion on the fractal dimension choice from a spatial distribution point of view, the impact of this choice on flow was illustrated. The sub-seismic fault models were modeled using different fractal dimension. Subsequently, an upscaling step using analytical upscaling (Oda, 1985) was performed. Finally by comparing the upscaling results of the fault networks, the choice of fractal dimension was characterized from a production point of view. Finally our modeling choice and simulation results were presented.

Characterizing sub-seismic faults has a major impact on the overall flow behavior of the field. The chosen methodology has been applied only on synthetic cases but never published using real data. This work will interest a practicing engineer. The fault network of these neighbor reservoirs allows us to illustrate the importance on the choice of fractal dimension for characterizing the fault network and its impact on the subseismic models and fluid displacement, consequently on production.
Understanding the Influence of Natural Fractures and Stress Anisotropy on Hydraulic Fracturing Design
Authors: Shetty Dinesh , Hillard Robert , Stegent Neil
Published: September 2019

In general, hydraulic fracturing design for unconventional reservoirs is performed using planar fracture model simulators. It is well known that the presence of natural networks combined with varying stress anisotropy can significantly impact the overall stimulation process and hence, associated oil or gas recovery.

In this study, a well-validated fracture simulator is used that explicitly accounts for the interaction between natural and hydraulic fractures under imposed stress anisotropy and performs transport of proppant in the induced complex network. Density of the natural fracture system is varied to study the scenarios, such as hydraulic fracture-governed mode and natural fracture-governed mode. For each of these scenarios, associated stress anisotropy is varied. These two parameters represent the properties of the formation that cannot be controlled. Then, multiple simulations are performed to understand the influence of design parameters, such as total slurry volume, pumping rate, and stage design for each set of fracture density and stress anisotropy. Many indicators are used, such as the stimulated fracture area, total proppant bed area, the area of the fracture above the bed, etc., to assess the efficacy of a design.

This study shows that, depending on the natural fracture density and the stress anisotropy, the benefits of pumping larger volumes of fluid to create longer fractures and effectively distribute the proppant diminishes. It also reveals that modification of the stage design can be utilized to alleviate this problem. The capability to transport proppant by increasing the pumping rate is observed to be strongly dependent on natural fracture density. The result also shows the importance of these factors for whole pad optimization because the natural fractures and stress anisotropy can significantly alter the maximum fracture length.

Thus, it becomes imperative to know the natural fracture distribution and the associated stress anisotropy to efficiently create a hydraulic fracturing design.
Unlocking Additional Barrels From a Mature Conventional Oil Field Through Unconventional Technologies: A Case Study on Rangely Oil Field, Colorado
Authors: Ketineni Sarath Pavan , Tan Yunhui , Hoffman Katrina L. , Jones Matthew , Ghoraishy Mojtaba
Published: September 2019

Demonstrating the viability of multistage hydraulic fractured horizontal wells to unlock otherwise trapped resources is presented through a case study on Rangely. A combination of high-fidelity reservoir models was employed for accurate forecasts and evaluation of hydraulically fractured horizontal wells to improve resources in this mature conventional oil field with ongoing pressure support and tertiary recovery operations. The modeling techniques used in this method can be extended to other mature oil fields to unlock bypassed oil setting a precedent to re-evaluate mature oil fields with the new unconventional completion technologies.

The Rangely Weber Sand Unit is an Eolian sandstone depositional system consisting of 2 billion bbls of oil in place. The Weber Formation is Pennsylvanian to Permian in age, and typically consists of fine-grained and cross bedded calcareous sandstones. Structurally oil is trapped in an anticline with varying dip angles on the flanks. The oil production from this reservoir was managed through primary depletion for the first two decades of production followed by secondary recovery via water flood and concluding through water alternating CO2 injection (WAG) over the last three decades. Due to the heterogeneity in depositional environment, the recovery factors have been low in the eastern end of the field. The east end of the field has relatively lower permeability and lower porosity compared to the rest of the field. A modeling workflow is presented to assist with evaluation and optimization of hydraulically fractured horizontal infill wells to recover bypassed oil in the eastern end of the Rangely field.

A full fidelity static model was built based on dense, high quality well control data. A sector model was history matched, and then used to update pressure, saturations, and stress distribution to present day. The history matched model was subsequently used to evaluate horizontal well performance and hydraulic fracturing completion options to overcome these heterogeneities and improve recovery from a lower quality reservoir.

Completions optimization opportunities were focused on fracture geometry, incremental Estimated Ultimate Recovery (EUR), and economics. Sensitivity studies demonstrated that an optimal balance of cost and recovery is found at the low end of fracture volumes and wider perforation cluster spacing. Forecasting runs show incremental economic recovery which otherwise could not have been recovered through ongoing WAG operations.
A New Process for Improved Oil Recovery from Water Injection by a Functional Molecule at 100 ppm Concentration
Authors: Kar Taniya , Chávez-Miyauchi Tomás-Eduardo , Firoozabadi Abbas , Pal Mayur
Published: September 2019

Low salinity water injection when effective in increasing oil recovery is often thought to be through increase in water wetting. Recently, oil-water interfacial rheology has been suggested to be related to oil recovery from low salinity water flooding. We have also discovered that addition of a very small amount of a functional molecule in the injection brine increases oil recovery significantly. Quantitative effect of interfacial elasticity and the effect of rock on oil recovery is investigated at 100 ppm concentration in this work for the first time. A light crude oil is used in four sets of waterflooding experiments in a carbonate rock. The injection brine is modified by adding 100 ppm of a non-ionic surfactant. To understand the recovery performances, interfacial viscoelasticity, interfacial tension and contact angle measurements are performed using brines of varying salinities. In interfacial rheology the effect of equilibration of the aqueous phase with the rock is also investigated. Additionally, adsorption of the surfactant in the carbonate rock is investigated for various aqueous phases via UVvis spectrometry. Crude oil, calcite and reservoir brine show moderate oil-wetting behavior. Addition of surfactant molecules makes the system more water-wet, however, the change is not pronounced. From coreflooding experiments, addition of surfactant in high salinity brine increases recovery by over 20% which we interpret to be due increase in interface elasticity. The phase angle which is a direct measure of interface elasticity decreases by 70% in an aqueous phase at about 4 wt% salt due to the surfactant. High interface elasticity reduces oil snap off and increases oil recovery. An effective molecule dissolved in water can increase the interface elasticity significantly. In relation to low salinity water injection we have established that there is an optimum salt concentration for high oil recovery. The injection of an aqueous phase without salt gives a lower recovery than injection of say 0.1 wt% salt in the injected water.

We have introduced a new IOR process based on interface elasticity which requires a very low concentration of a non-ionic surfactant. The process is neither through wettability alteration nor through significant change in IFT. The chemical we have used is environmentally friendly and of low cost. It has very low adsorption onto the rock surface.
Estimating Fracture Network Area and SRV Permeability by Analyzing Offset Well Pressure Measurements during Fracturing
Authors: Seth Puneet , Manchanda Ripudaman , Elliott Brendan , Zheng Shuang , Sharma Mukul , Hwang Jongsoo
Published: September 2019

During stimulation of unconventional reservoirs, offset well pressure measurements are often used to estimate hydraulic fracture geometry. These measurements can also be used to make a quantitative estimate of the created fracture network area and the permeability of the stimulated rock volume (SRV) around the hydraulic fractures. Offset well pressure measurements recorded in the field clearly show a change in the pressure response of the monitor well when the injection rate in a nearby fracture treated well is changed. The shut-in period between two frac stages in the treatment well corresponds to a distinct pressure fall-off in the monitor well. We present a workflow where we analyze and match this pressure fall-off in an offset monitor well in response to fluid leak-off from a hydraulic fracture in the treatment well to estimate SRV permeability and the created fracture network area. The workflow and model are applied to field data from the Permian Basin.

A fully-coupled, 3-D, poroelastic reservoir-fracture simulator has been used to simulate pressure fall-off in the offset monitor well. Field data and simulation results are presented to show that during shut-in between two frac stages in the treatment well, a decrease in the injection rate causes the monitored offset well pressure to fall-off. We find that this fall-off in pressure is influenced by leak-off from the treatment well fracture. During the shut-in period, fluid leak-off from the treatment well fracture into the SRV region decreases the width of the fracture which consequently affects the stress-shadow and the poroelastic pressure fall-off in the offset monitor well. The pressure fall-off in the monitor well is, therefore, shown to be caused by 1) the fluid leak-off from the monitor well fracture and 2) stress-shadow relaxation around the monitor well fracture as fluid leaks-off from the nearby treatment well fracture into the formation.

We present a new method to estimate the permeability of the stimulated region around the created fractures. We show that, along with the permeability of the SRV region, the stress-shadow of the treatment well fracture on the monitor well fracture also has a significant impact on the pressure fall-off in the monitor well. We use a conceptual model to estimate the created fracture network area which can be used as a metric to identify the effectiveness of a frac job and provide insights into the generated fracture complexity during the frac job. In addition, the estimated SRV permeability and fracture network area are critical inputs in production forecast simulations that can guide an operator to make better economic decisions in a relatively inexpensive manner.
Improved Communication and Autonomy with Downhole Memory Logging Tools
Authors: Kupchenko Shawn , Gilhooley Neill , Ash Sam , Carrahar Alyn
Published: September 2019

Openhole logging tools have been used without wireline in memory logging for 20 years, in an important and growing market. A new system in field trials in Canada and Russia in 2019 further expands the operating envelope overlap between wireline and logging-while-drilling by making step changes in communications, autonomy, performance, and reliability. The new approach advances the logging of horizontal and challenging wells, and permits operations in managed pressure drilling and foam drilled wells.

The vast majority of openhole memory work is achieved with a hydro-mechanical system that indicates successful deployment but lacks two-way communication between the engineer at surface and the tools downhole. Pressure-pulse communications have been used for 10 years with a wide range of measurements including memory logging with wireline formation testers. The experience gained from operating these systems informed the development of a new system that uses drillpipe rotation to communicate to the tools, pressure pulses to reply for the uplink, and a more powerful downhole processor. These enhancements in autonomy and communication improve the outcome of logging jobs.

The system incorporates a new rotation downlink method which employs data from an angular rate sensor to identify a series of commands sent by rotating the drillstring. Control software in the downhole tools executes the commands, and replies are transmitted uphole by pressure pulses. The toolstring is released from a safe ‘garage’ position inside the drillpipe and deployed into openhole, with the top of the toolstring retained by a no-go. The engineer is supplied with far more diagnostic information than previously, including the axial position of the tools, with context sensitive encoding to provide maximum troubleshooting information to the surface over a limited bandwidth channel. The pressure-pulse downlink remains in place as a secondary method. Other material improvements include high data sampling rate, debris tolerance and downhole recovery strategies. All of these advances improve the autonomy of the downhole memory equipment as well as the real-time communication and control from the surface.

Autonomous memory logging toolstrings, with powerful downhole software and rotation downlink communications, are important components in improving the performance and reliability of these successful and innovative formation evaluation systems.
An Early Production Comparison of Northern White Sand and Regional Sand in the Permian Basin
Authors: Williams Ryan , Artola Pedro , Salinas Javier , Mirakyan Andrey , MacKay Bruce , Hoefer Ann , Kraemer Chad , Reese Harrison , Roybal Zack , Williamson Brant
Published: September 2019

Use of regional sand in the Permian Basin dramatically increased in 2018. Regional or in-basin sand is often perceived as lower quality compared to northern white sand (NWS); however, its use is fairly new, and production data has not been available to determine if, or in what cases, higher quality matters. This paper presents the results from a production comparison of Permian Basin wells that were hydraulically fractured with NWS and regional sand or both.

A dataset consisting of approximately 450 wells completed with NWS or regional sand or both within the Delaware and Midland Basins was studied to determine the relationship between production performance and sand type (or quality). To evaluate the effect of sand quality in well production, the dataset was divided in smaller groups of wells with similar reservoir characteristics and completion practices. The initial phase of the study was completed using public domain production data, while the second phase focused on the development of regional reservoir models to forecast production of wells using NWS or regional sand or both.

When analyzing an area containing sufficient wells for a reliable comparison, the survey revealed no statistically significant difference in production for wells that used NWS versus regionally sourced sand. Models were built to predict differences in the production performance of each sand type. These models take into account and demonstrate the effects of differences in sand properties, as well as the impact of the favorable economics associated with regional sands. It was confirmed with the study that the sand type is not a critical factor in regards to production performance when completing wells that are hydraulically fractured in ultralow-permeability nonconductivity-limited reservoirs.

This paper presents an early look at the production numbers of West Texas wells completed with regionally sourced sand in the Permian Basin. The results of the study will encourage operators to further contemplate the use of regional sand when completing wells in ultralow-permeability shale reservoirs. This dataset will continue to evolve and reveal the effects of regional sand over the life of the well; this will be presented in a future paper.
A Risk-Based Approach to Evaluating, and Rationalizing, the Portfolio of Company HSE Programs
Authors: Cunningham Andrew , Wentzel Nada , Knode Tom , Pooley Tony
Published: September 2019

In order to improve HSE performance many companies have implemented voluntary (i.e. non-regulation driven) programs designed to engage supervisors and employees and reduce injuries and incidents. Over the years these programs have had significant effect in improving performance and making the workplace safer. While done with the best intentions, most programs introduce an element of administrative burden on the organization and sites. The cumulative impact on a supervisor's daily activities can be substantial and result in excessive time spent in front of a computer, rather than with their teams. This means less opportunity to provide leadership on safety and consequently, undermine efforts to improve.

In 2017, based on a combination of employee surveys and safety stand downs Dyno Nobel North America (‘DNA’ or the company), a global explosives manufacturer and service provider, identified the need to evaluate the burden on the organization of safety programs to rationalize and improve them as appropriate. One of the main concerns of this effort was how to remove or modify these programs to be less of a burden, yet not increase the risk. It can be related to the game Jenga®, where players remove blocks from a stack without destabilizing the structure.

DNA engaged a consultant, The Jonah Group, to build a risk model based on the principles of process safety management interwoven with the understanding of human factors and performance. Once the model was built, it was piloted at three of the company's field sites to ensure efficacy and adjust as necessary. Afterwards, the model was used at nine field locations. The evaluation included a review of equipment, process and procedure, and centered around interviews with supervisors and front-line employees. Surveys were conducted with supervisors to complete the view of where they spend their time.

Results and recommendations were summarized in a report. One of the key findings was that while there were opportunities to improve certain elements of the voluntary safety programs, there were more significant opportunities with regards to management of change, process safety and risk awareness, site safety leadership, communication, and process efficiency. The recommendations will help the company improve organizational effectiveness and free up supervisors to better oversee, and lead, site safety.
Numerical Investigation of EOR Applications in Unconventional Liquid Reservoirs through Surfactant-Assisted Spontaneous Imbibition SASI and Gas Injection Following Primary Depletion
Authors: Zhang Fan , Saputra I. W. , Adel Imad A. , Schechter David S.
Published: September 2019

Surfactant-Assisted Spontaneous Imbibition (SASI) and gas injection have been proven to improve production from Unconventional Liquid Reservoirs (ULR). However, the novelty of the method has resulted in a few publications to date. This study utilizes numerical modeling to upscale laboratory data of SASI for completion purposes and gas injection plus SASI for EOR. Novel gas and aqueous-phase injection strategies following primary depletion are designed based on actual completion and production data. Multiple sequencing configurations for both surfactant and gas injection are tested to propose the best combined-EOR scheme for ULR.

Parameters related to the mechanism of SASI and gas injection are retrieved from CT-generated core-scale model of laboratory experiments. SASI and gas injection experimental results were upscaled to model production response of a hydraulically fractured well with realistic fracture geometry and conductivity. The core-scale model was created to determine the diffusion coefficient, relative permeability, and capillary pressure curves by history-matching the laboratory data. The field-scale model was developed with a dual-porosity compositional model to predict production enhancement for various combined-EOR schemes in ULR.

Wettability and IFT alteration are the two primary mechanisms for SASI in enhancing production. Experimental studies revealed that surfactant solution recovered up to 30% OOIP, whereas water alone only recovered approximately 10% OOIP. Capillary pressure and relative permeability constructed from scaling group analysis and core-scale numerical models showed that surfactant addition enhances the two curves. On the other hand, gas injection EOR was found to be driven by multi-contact miscibility and diffusion. Parameters related to both methods were applied to the field-scale model for multiple completion and EOR schemes. Results demonstrate that the combination of SASI and gas injection possesses significant potential in improving production rates and estimated ultimate recoveries (EUR) in ULR. Soak times, surfactant concentration, injection pressure, duration of the cycle, and cumulative gas injection control the level of enhancement. With a large number of control variables, specific customizations can be optimized to suit criteria of different field applications.
Overcoming Geological and Geomechanical Challenges for Drilling High Angle Well in Deep Offshore Gulf of Mexico: Example from Buckskin
Authors: Ait-Ettajer Taoufik , Giannangeli Federico , Wood Jonathan , Mookanahallipatna Lakshmikantha
Published: September 2019

The Gulf of Mexico, and more precisely the Wilcox trend, has long been considered as challenging area for developing profitable hydrocarbon fields. In fact, the safe drilling of deep offshore wells needs to take into account the geological and geomechanical complexities, generated by the different sedimentological and tectonic events that accompanied the development of the Wilcox trend.

In the case of Buckskin field, located in Keathley Canyon protraction (Figure 1), and in order to overcome those challenges, we developed a workflow that ranks all the parameters related to the geometry, the geology, the rock quality and the geomechanics characteristics of the reservoir. The core of the workflow is articulated around a probabilistic method that will assess the uncertainty of the productivity index, based on experimental design and Monte Carlo simulation. The proposed workflow allowed the optimization of the PI of the well thanks to a highly deviated reservoir section at a depth below 24,000’, combined with an optimal fracking job.Figure 1Location of Buckskin field

After a brief introduction of the general context of the Buckskin field, we will review the notion of the PI, then we will review the adopted process prior to the geological and geomechanical processes for modeling the rock properties and stresses and their corresponding uncertainties. The selected design of experiment approach will then be described then we will discuss the outcome.
Educating Future Drilling Engineers for the Digital Era
Authors: Eustes III Alfred W. , McKenna Kirtland I. , Zody Zach J. , Healy Carl , Lang Camden , Joshi Deep , Yow Stephen , McGowen Kyle
Published: September 2019

Drilling education must evolve continuously to keep up with the changes in the drilling industry. Part of that evolution includes the addition of data analytics in drilling operations. In addition, having a "hands on" experience of actual drilling operations is an important part of the drilling engineering educational process. At the Colorado School of Mines, both goals are achieved using a new coring rig equipped with a high-frequency data acquisition system.

A Sandvik DE 130 Diamond Coring Rig was acquired by the school through a grant from Apache Corporation that has proven to be an excellent analog to full-scale petroleum rigs. It has all drilling subsystems such as rotary, hoisting, power, and circulation. A data acquisition system has been added that tracks accelerations as well as various drilling operational parameters. During experiments, each student has an opportunity to operate the driller's controls and experience the complexities associated with drilling operations including the occasional error. The retrieved core helps the student correlate the formation with drilling data.

The inclusion of the drilling experience in the curriculum has benefited the students in several aspects. This experience has helped students visualize drilling operations and understand complexities and challenges associated with drilling. During the drilling operations, if any problems arise, the students have a chance to troubleshoot those problems in real-time and apply their theoretical knowledge. Operational safety and stop work authority are also a focus and demonstrated by students. This is likely to be the first experience most students have with high-frequency drilling data analysis. Monitoring, collecting, and handling real high-volume data gives a first glimpse into the complexities of data analytics. Noisy realtime data and errors are real and observed by the students. They also learn to handle and analyze high- frequency drilling data identifying normal trends and abnormalities. This coring rig has enhanced the drilling engineering education and data analysis skills of our students.

This work outlines a novel teaching methodology that combines the practical understanding of drilling and the application of data analytics. Getting out to the field and actually drilling rock has enhanced our drilling curriculum to align it with the latest industry practice and to educate future drilling engineers.
iSCAL for Complete Rock Characterization: Using Pore-Scale Imaging to Determine Relative Permeability and Capillary Pressure
Authors: Lin Qingyang , Alhammadi Amer M. , Gao Ying , Bijeljic Branko , Blunt Martin J.
Published: September 2019

We combine steady-state measurements of relative permeability with pore-scale imaging to estimate local capillary pressure. High-resolution three-dimensional X-ray tomography enables the pore structure and fluid distribution to be quantified at reservoir temperatures and pressures with a resolution of a few microns. Two phases are injected through small cylindrical samples at a series of fractional flows until the pressure differential across the core is constant. Then high-quality images are acquired from which saturation is calculated, using differential imaging to quantify the phase distributions in micro-porosity which cannot be explicitly resolved. The relative permeability is obtained from the pressure drop and fractional flow, as in conventional measurements. The curvature of the fluid/fluid interfaces in the larger pore spaces is found, then from the Young-Laplace equation, the capillary pressure is calculated. In addition, the sequence of images of fluid distribution captures the displacement process. Observed gradients in capillary pressure – the capillary end effect – can be accounted for analytically in the calculation of relative permeability.

We illustrate our approach with three examples of increasing complexity. First, we compare the measured relative permeability and capillary pressure for Bentheimer sandstone, both for a clean sample and a mixed-wet core that had been aged in reservoir crude oil after centrifugation. We characterize the distribution of contact angles to demonstrate that the mixed-wet sample has a wide range of angle centred, approximately, on 90°. We then study a water-wet micro-porous carbonate to illustrate the impact of sub-resolution porosity on the flow behaviour: here oil, as the non-wetting phase, is present in both the macro-pores and micro-porosity. Finally, we present results for a mixed-wet reservoir carbonate. We show that the oil/water interfaces in the mixed-wet samples are saddle-shaped with two opposite, but almost equal, curvatures in orthogonal directions. The mean curvature, which determines the capillary pressure, is low, but the shape of the interfaces ensures, topologically, well-connected phases, which helps to explain the favourable oil recovery obtained in these cases.

We suggest that the combination of imaging and flow experiments – which we call iSCAL – represents a compelling development in special core analysis. This methodology provides the data traditionally acquired in SCAL studies, but with insight into displacement processes, rigorous quality control, and flexibility over sample selection, while generating detailed datasets for the calibration and validation of numerical pore-scale flow models.
Maximizing Organizational Effectiveness by Creating a Culture of Alignment
Authors: Lau Hon Chung , Pang Michael
Published: September 2019

Oftentimes an organizational transformation fails not because of external reasons but internal resistance. A step often neglected by senior management in organization transformation is aligning the transformation process with the corporate culture. When a transformation works against established corporate culture, it will be rejected by the organization and will eventually fail despite the best efforts by senior management. However, if an organization transformation is closely aligned with the corporate culture, its chance of success is greatly enhanced. In this paper, we propose a step-by-step procedure to align an organization transformation process with the four layers of corporate culture. This can be pictorially illustrated by the Corporate Cultural Onion Model and the Simple Lever Model of Organizational Alignment.
Bringing Uncertainty to the Forefront of Informed Decision Making in Oil and Gas Exploration and Development
Authors: Wanjau Paul , Bloomfield Rory , Bauer Jennifer , Rose Kelly
Published: September 2019

As data computing and big data driven analytics become more prevalent in a number of spatial industries, there is increasing need to quantify and communicate uncertainty with those data and resulting spatial analytical products. This has direct implication in oil & gas exploration and development where big data and data analytics continue to expand uses and applications of spatial and spatio-temporal data in the industry without providing for effective communication of spatial uncertainty. The result is that communications and inferences made using spatial data visuals lack crucial information about uncertainty and thus present a barrier to accurate and efficient decision making. With increasing cost awareness in oil & gas exploration and development, there is urgent need for methods and tools that help to objectively define and integrate uncertainty into business decisions.

To address this need, the Variable Grid Method (VGM) has been developed for simultaneous communication of both spatial patterns and trends and the uncertainty associated with data or their analyses. The VGM utilizes varying grid cell sizes to visually communicate and constrain the uncertainty, creating an integrated layer that can be used to visualize uncertainty associated with spatial, spatio-temporal data or data-driven products.

In this paper, we detail the VGM approach and demonstrate the utility of the VGM to intuitively quantify and provide cost-effective information about the relationship between uncertainty and spatial data. This allows trends of interest to be objectively investigated and target uncertainty criteria defined to drive optimal investment in improved subsurface definition. Examples are presented to show how the VGM can thus be used for efficient decision making in multiple applications including geological risk evaluation, as well as to optimize data acquisition in exploration and development.

Today, uncertainty, if it is provided at all, is generally communicated using multiple independent visuals, aggregated in final displays, or omitted altogether. The VGM provides a robust method for quantifying and representing uncertainty in spatial data analyses, offering key information about the analysis, but also associated risks, both of which are vital for making prudent business decisions in oil & gas exploration and development.
Permeability Logging through Constant Pressure Injection Test: In-Situ Methodology and Laboratory Tests
Authors: Manivannan Sivaprasath , Bérest Pierre , Jacques Antoine , Brouard Benoît , Jaffrezic Vincent , De Greef Vincent
Published: September 2019

In wells producing water, oil, gas or geothermal energy, or in access wells to hydrocarbon storages, it is critical to evaluate the permeability of the formation as a function of depth. Continuous permeability logs in these wells are typically derived using tools that measure electrical, nuclear, magnetic or acoustic signals, using empirical relations that are often formation dependent. The permeability logs derived using these empirical relations often show significant differences when compared to the permeabilities obtained from core samples or well tests.

A new technique is proposed in this paper in which the open hole is scanned with an interface between two fluids with a large viscosity contrast. The injection rate into the formation depends on interface location and well pressure history. An inverse problem is solved to estimate permeability as a function of depth from the evolution of flow rates with time. During the test, the well is equipped with a central tube, typically a drill string, and the scanning is done by injecting in the central tube a liquid that is different from the liquid in the annulus, at a constant wellhead pressure. Injection and withdrawal rates are measured at the tubing and the annulus wellheads, respectively; the difference between these two rates gives the formation injection rate. Interface location is also estimated from the flow rates and pressure at the wellhead and an injection profile in the open hole is derived.

A permeability log is derived from this injection log by considering a radial, monophasic flow in each layer and same skin value for all formation layers. Initial formation pressure and storativity, estimated from other logs, are also used as inputs. The sensitivity of the permeability log to these inputs is estimated using analytical expressions. The proposed methodology is applicable to oil or water bearing formations drilled using oil or water-based muds, respectively.

A continuous permeability log is estimated from the synthetic test data using the proposed interpretation workflow; it shows a correlation of 0.95 (on a scale of 0 to 1) when compared to the input permeability log. A laboratory model that mimics a multi-layered formation is used to study the repeatability of the technique and the validity of the uniform skin assumption by creating a mudcake at the inner radius. Four consecutive tests were performed on the same set of samples and the interpreted permeability logs are compared to the benchmark permeability log; correlations are greater than 0.94.