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Summary Produced water (PW) is an undesirable byproduct generated from oil and natural gas production. Due to the large volume produced, managing its disposal is challenging. Generally, PW is used internally for oil and gas operations while different types of means dispose of the remaining volumes. Recently, there has been a need to repurpose the volume of water customarily disposed of for other industries’ applications. This presents a potential opportunity to reduce excessive freshwater usage in oil and gas operations and reduce water depletion in other industries, thus aiding water conservation as one of the goals for sustainable development. While the external uses are the viable and logical solution, there are challenges relating to PW characterization, treatment technology, and economics of such a project. Therefore, the effective treatment technology, utilization, and disposal of PW remain critical issues for the petroleum industry with consideration of the environment, technical aspects, and economics. There must be collaboration among all stakeholders to harness the potential opportunities and merits of external reuse of PW for cost-effective and environmentally sustainable solutions in treatment technology and every other aspect of PW management. This review presents a comprehensive overview of PW management, current practices in the petroleum industry, and opportunities to be used in other sectors. A detailed account of each disposal method and possible external uses are enumerated with associated challenges, and how these can be mitigated.

Modern data analytic techniques, statistical and machine-learning algorithms have received widespread applications for solving oil and gas problems. As we face problems of parent–child well interactions, well spacing, and depletion concerns, it becomes necessary to model the effect of geology, completion design, and well parameters on production using models that can capture both spatial and temporal variability of the covariates on the response variable. We accomplish this using a well-formulated spatio-temporal (ST) model. In this paper, we present a multi-basin study of production performance evaluation and applications of ST models for oil and gas data. We analyzed dataset from 10,077 horizontal wells from 2008 to 2019 in five unconventional formations in the USA: Bakken, Marcellus, Eagleford, Wolfcamp, and Bone Spring formations. We evaluated well production performance and performance of new completions over time. Results show increased productivity of oil and gas since 2008. Also, the Bakken wells performed better for the counties evaluated. We present two methods for fitting spatio-temporal models: fixed rank kriging and ST generalized additive models using thin plate and cubic regression splines as basis functions in the spline-based smooths. Results show a significant effect on production by the smooth term, accounting for between 60 and 95% of the variability in the six-month production. Overall, we saw a better production response to completions for the gas formations compared to oil-rich plays. The results highlight the benefits of spatio-temporal models in production prediction as it implicitly accounts for geology and technological changes with time.

The is wide consensus that combustion of fossil fuels and rising greenhouse gas emissions in the atmosphere are accelerating global warming. To avoid the dilemma of need for fossil fuels to provide energy supply and the need to reduce fossil fuel related emissions, it is critical to promote renewable energy as a viable option to satisfy the world's energy requirements. However, employing renewables to generate power necessitates the use of bulk storage to accommodate discrepancies related to where and when renewable energy is produced versus where and when it is needed. Underground hydrogen storage has the potential to support establishment of hydrogen as a reliable source of clean energy across the planet. Where present, depleted oil and gas reservoirs, due to their existing infrastructure, can prove to be an attractive asset for underground hydrogen storage. One of the main challenges involved in the storage of hydrogen in the depleted oil and gas reservoirs is related to wellbore integrity. When hydrogen is injected or produced in the subsurface, it may get bin contact with cement around the wellbores. Hence it is necessary to investigate the effects of hydrogen interacting with the cement sheath. To study this in the laboratory, a core holder capable of simulating the wellbore conditions is used to conduct the tests. A 2" long, 1.5" diameter cement sample was placed inside the core holder and hydrogen was injected into it. Hydrogen was also injected into wet cement slurry to investigate possible stability of the cement samples. The effects of injecting hydrogen on set cement are studied using a CT Scanner which demonstrates if there is any formation of cracks and micro-annuli in the cement. The cement sample is crushed afterwards, and the presence of hydrogen particles in the structure of cement is evaluated by X -Ray Diffraction. A neat 15.5 lbs./gal Class "H" cement which is common in the industry is used in this study. Well integrity is a key success factor to establish the viability of underground hydrogen storage in the subsurface. For that we analyzed if the cement is good enough for hydrogen to be stored in depleted oil and gas reservoirs. We further studied the integrity of newly drilled wells when exposed to hydrogen.

Produced water is naturally occurring water that is produced as a byproduct during the exploration and production of oil and natural gas from the subsurface system. Produced water brought to the surface contains high saline content and may also contain Naturally Occurring Radioactive Material (NORM). Therefore, the efficient treatment, use, and disposal of produced water remain a critical issue for the energy industry with environmental and human health implications. Over the years, researchers have presented numerous treatment technologies ranging from physical, chemical, and biological perspectives. Some industries have combined one or two of these methods to improve the treatment quality of produced water required for distinct purposes, and these practices have been extended to the energy industry. As the energy industry strives to sustain production capacities and maintain or increase profitability in this energy-transition era, water production is also rising while there is a reduction in its re-purposing and utilization for energy and environmental industries. Our study focuses on over 100 studies conducted over the past five decades. This study presents a comprehensive overview of the produced treatment methods, challenges regarding the execution and implementation of these methods in the energy industry. We highlight the important fundamental questions that are yet to be addressed and propose new directions for more environmentally friendly and economically viable solutions for the treatment and use of produced water.

This paper provides a feasibility study for the noncontact detection and monitoring for the presence of moving gas phases in gas-liquid flows based on portable mm-wave Doppler radars. The identification of moving gas phases is of paramount importance in a large range of areas such as petroleum, biomedical, and food processing industries. Several experiments were carried out to verify the feasibility of the non-invasive air bubbles detection using Doppler radars. The mm-wave radar sensor captures and down-converts the microwave signal, which is phase-modu-lated by the linear motion of the air-water interface inside the pipe. The high sensitivity of the mm-wave radar sensor also allows the estimation of the speed of the air bubbles.

Several oil and gas industry applications of artificial intelligence have been presented in the last decade. Machine learning techniques take center stage in most presentations. Prior to performing the actual modeling in data analytic project, the first three steps in the data analytic lifecycle involve planning, data preparation and model planning. Data visualization is an important aspect in the model planning phase as it aids in selecting variables that are important for modeling and in deciding the appropriate choice of ST model to use. Hence, it is important to invest time and resource to carry out this aspect of the project in order to delineate patterns in the dataset. Researches conducted in this area in the oil and gas industry have not maximized the power of visualizations, particularly when it comes to spatio-temporal data analysis. In this paper, we present applications of spatio-temporal exploratory data analysis for oil and gas datasets using ST-plots, applied on dataset from four unconventional formations in the US: Bakken, Marcellus, Eagleford and Wolfcamp and Bone Spring formations in the Delaware Basin. Several plots are presented, including space-time plots, animations, Hovmöller diagrams,temporal histograms, and boxplots – capturing variations in oil and gas production across space and time. In the first plot, we show variation in yearly oil production across space with different panels representing time domains. This plot shows the development of an area with few wells in the initial stages and additional wells in later stages. Colors can be added to capture the magnitude of the yearly oil/gas production, normalized with days produced. Areas of the field that contribute to higher production becomes apparent. Animations can be used to present this data monthly as is typical in production data reported to state agencies. For unconventional formations, further normalization can be done with the number of completion stages or lateral length. Hovmöller diagrams are good alternatives with space on the x-axis and time on the y-axis. This plot enables us capture spatial (in)dependence of the dependent variable and can suggest the use of space as a covariate in the final model. Another plot that could be useful is the temporal histogram, in which the third dimension is time. This plot could be useful in deciphering a suitable model for the data and clearly show if the distribution or average changes over time. We highlight how these plots aid in variable selection for spatio-temporal modeling of production data. These plots are not the typical plots used in presenting oil and gas data and hence the application is new in this regard, in addition to the temporal histogram and boxplots which are new additions.

Hydraulic fracturing is a very complex process that has not yet been fully understood. Furthermore, the number of stages, length of fracture clusters in each stage, proppant and fracturing fluid compatibilities, optimum spacing length, proppant transport and placement, proppant and frac-fluid compatibility, and optimum spacing are some of the challenges inhibiting successful application of this technique across the world. In this study, we present the impact of fracture-cluster lengths, proppant types and sizes, proppant densities, frac fluid types, fluid viscosities, and injection rates on hydraulic fracturing process. Firstly, we developed a stress profile to determine initiation location and orientation of the hydraulic fractures, and subsequently created the geological layering in the zone of interest. We grouped our investigations into 5 case studies, followed by developing an efficient hydraulic fracturing design approach, and we determined the optimal treatment to achieve maximum recovery. Our results show that fracture clusters with optimal lengths will provide optimized hydraulic fracture treatment. In addition, high-strength proppants is efficient for shale formations with closure stress exceeding 5000 psi to achieve optimum fracture conductivity and fracture half-length. Furthermore, we observed the high-density proppant produced greater fracture lengths and lower dimensionless fracture conductivity (CFD), while the low-density proppant produced greater effective propped-fracture lengths and higher CFD. In some of the cases investigated, we observed that stress shadowing and interference can hinder fracture growth, eventually led to a collapse of some fractures. Our results provide valuable critical decision-making insight for optimizing hydraulic fracturing process in unconventional reservoirs across the world.

Objective: An expert reference group met on four occasions to consider ways forward in terms of Indigenous mental health. This paper summarises the discussion and recommendations. Conclusion: While the negative effects of colonisation and trans-generational trauma continue, we propose renewed emphasis on improving access, cultural orientation and trauma-informed care, and a focus on the needs of young Indigenous Australians.

Objectives/Scope: Graduate and undergraduate petroleum engineering degrees and enrollments are presented. Causes and effects of huge changes in enrollment and degrees granted over the past sixty years are discussed. The impacts on the future of the petroleum industry’s available new engineers and sources of these talents are presented. Methods, Procedures, Process: United States petroleum engineering enrollments and degrees granted since the 1950’s have been collected from AIME (SPE’s mother institution) sources, SPE’s annual enrollment reports, and more recently surveys of the petroleum engineering department heads. Additional input from SPE’s standing Education and Accreditation Committee and Professionalism Committee are included. Approximately a dozen Colloquiums on Petroleum Engineering Education (CPEE) have been held over the past twenty-five years at locations in the US and other areas of the world. These CPEE discuss enrollment trends, job placement, industry needs and have resulted in significant advancements to petroleum engineering education. Over the last year information has been collected to include five years from non-US programs. Enrollment is compared to inflations adjusted oil prices. Lastly, a look at international petroleum programs as compared to SPE membership changes on a global basis. Results, Observations, Conclusions: This paper presents the following results, observations and conclusions: Petroleum Engineering enrollment and the resulting degrees granted are affected by oil and gas prices. These changes lag price by 2.5 years. The Recent peak in Bachelor of Science (BS) degrees granted 2550 (in 2017) are projected to drop 980 (in 2020). The pipeline to produce new engineers is four to five years long. As industry petroleum engineer requirement increases, it will take several years to increase the supply from previous conventional sources (programs/universities).

The quest for excellence and efficiency in academia and education is critical. Some of the best proven methods of assessing educational programs refer to the standards and approach developed by ABET (The Accreditation Board for Engineering and Technology). This institution which was initiated originally in the US is involved in the supervision and accreditation of more than 3750 educational programs spread internationally over 30 countries. The Bob L. Herd Department of Petroleum Engineering has been using these standards since its ABET accreditation 66 years ago. It is still striving for excellence, improvement and perfection since then. The goal is to produce the best petroleum engineers using the last Student's Outcome approach (SO) and assessment methods as developed by ABET. ABET approach uses various tools to assess educational programs, some of which are conventional such as: Examinations, quizzes, guided homework's, term projects etc. others are more involved. The data are translated into quantifiable parameters for analysis. In addition to all these tools, this study uses one more that has been proven to be valuable and added to the arsenal available at the Bob L. Herd DPE. It is the use of visualization labs. This consists of models built to simulate various forces, physical mechanisms and engineering concepts encountered in drilling, production and reservoir engineering. The present study is directed toward the use of petrophysical or scaled models to enhance the methods of education in petroleum engineering and more specifically in reservoir engineering. Scaled models are not new in the oil industry. They used to be the only way to study oil reservoirs and forecast their behavior until the advent of computers and numerical simulation in the 1970's. Several scaled models designed to simulate water-flooding processes for educational purpose are used by students to complete projects on reservoir development. Analysis of the results shows the following: After completion of the projects, students have a better understanding of the fundamental concepts and principles behind reservoir engineering, depletion mechanisms and other issues related to fluid displacement in porous media.The Metrix associated with the student outcome and assessment methods developed for ABET evaluation showed that a well-conceived visualization lab can be extremely effective in petroleum engineering education in general and more particularly in reservoir engineering.

Spatial data exists practically everywhere, including the oil and gas industry. Several factors drive the distribution of the location of oil and gas wells: performance of existing wells, available acreage, need for operators to maintain a certain amount of production and to stay competitive. Some of the important parameters to consider in the design of a completion job for an unconventional oil and gas well are the length of lateral (and by extension perforated interval), number of stages, total pounds of proppants, total volume of fluid pumped, injection pressure and injection rate. In big data analytics and building of a regression model to capture the effects of these parameters on oil production, the practice has been to analyze wells in similar formations or similar basins, even when these wells are miles apart. Due to the presence of spatial autocorrelation and non-stationarity in such data, the recommended practice should be to take these spatial dependencies into account by using geographically weighted regression (GWR). In this paper, we present an application of GWR in location-based regression modeling to capture the effect of these completion parameters on the first six months of oil production in 5700 wells in the Bakken and Three Forks formation in North Dakota. GWR builds different models for every location, leading to a spatial distribution of variable coefficients. This model is well suited to capture both local and global variations in our dependent variable. We also compare the results obtained with that of three other models: multiple regression model, artificial neural network model and universal kriging. Just like the use of kriging, GWR model resulted in a much-improved prediction of oil production as captured by the goodness-of-fit diagnostics (R squared, AIC, and RMSPE), compared to the other two non-location-based models. We recommend the use of the GWR model in the prediction of oil or gas production when spatial non-stationarity exists.

The separation of gas from gas-liquid mixture in horizontal wells has become a growing concern in the oil and gas industry. The produced free gas reduces the efficiency of rod pump systems, minimizes oil production and can lead to the failure of the rod pump system due to gas locking phenomena. The impact of two-phase flow on the new horizontal well gas anchor’s performance was investigated experimentally. Each experiment was conducted in a transparent horizontal well flow loop by using water and air as the test fluids. Experiments with and without the new gas anchor in the flow loop cases were studied. The new tool has two mechanisms to prevent gas phase from entering the tubing. The first mechanism is the breakage of the mixture’s wave by the bull plug of the tool. The second mechanism is the separation of small gas bubbles due to the flow through the tortuous path inside the tool. This experimental program quantifies the tool performance regarding the first working mechanism only. The bubble separation via the tortuous path mechanism was not investigated. The results showed that both with and without tool cases can separate 90 – 100% gas from the mixture, if the inlet of tubing or the tool was fully submerged under liquid phase of the mixture at all time. This condition was achieved under stratified flow where the horizontal part of the well was toe flat or toe-up (0°, +1°, and +2°). The wave breakage mechanism by the bull plug of the tool was confirmed visually. This breakage mechanism established the advantage of using the new gas anchor over no-tool condition.

The prediction of unconfined compressive strength (UCS) of oil well cement class “H” based on the artificial neural network (ANN) modeling approach is presented in this study. 195 cement samples were embedded with varying dosages of strength enhancing pre-dispersed nanoparticles consisting of nanosilica (nano-SiO2), nanoalumina (nano-Al2O3), and nanotitanium dioxide (nano-TiO2) at various simulated wellbore temperatures. The efficacy of the pre-dispersed nanoparticle solutions was analyzed by transmission electron microscope (TEM) images. Nano-SiO2 and nano-Al2O3 displayed excellent dispersibility throughout the solution. However, nano-TiO2 readily agglomerates which, at high concentrations, is detrimental to the UCS of cement. 70% of the data set was used to train the ANN model, 15% was used for validation, and 15% was used to test the model. The model consisted of one input layer with five nodes, one hidden layer with 12 nodes, and one output layer with one node. 12 nodes in the hidden layer resulted in the lowest mean squared error (MSE). The model parameters were saved and used after seven epochs during training, at which point the validation error began to increase leading to overfitting. The statistical performance measures consisting of MSE, the square root of the coefficient of determination (R), and the mean absolute percentage error (MAPE) showed values close to zero, one, and less than five percent, respectively. The statistical performance measures of the ANN model displayed superior results when compared to the measures obtained by the multi-linear (MLR) and random forest (RF) regression algorithms. The developed ANN model displays high predictive accuracy and can replace, or be used in combination with, destructive UCS tests which can save the petroleum industry time, resources, and capital.

During unconfined compressive strength (UCS) tests of oil well cement, it is not uncommon for standard cubic test specimens to require some processing in order to meet the requirements of end face planarity and parallelism. Also, unique research scenarios may produce cement specimens for which UCS data is required but that deviate slightly from the 50.8 mm cube shape recommended by API for testing UCS of oil well cements. Little has been published with regards to the effect of such minor specimen shape variations on the UCS value measured or on the acceptability of the obtained measurement. Thus, different oil well cement formulations of varying compressive strength were tested for UCS using different specimen shapes and sizes in order to quantify the effect of geometry on the measured UCS. The shapes and sizes tested were chosen to cover the range of sizes that could result due to slight deviations from the API-recommended standard testing geometry. The validity of the UCS measurement for each specimen geometry was also tested for validation using statistical techniques outlined in ASTM C109 and ASTM C670. The results of this study show that there are no discernable direct size effects for the range of sizes tested even though the shape and size strongly affect the reliability or validity of the UCS reading.

Throughout fracturing treatment, millions of gallons of water are injected, but commonly less than 50% is recovered after stimulation. This study was constructed to evaluate the impact of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. Different pad fluids types were considered including; friction reducer fluid, friction reducer with a non-ionic surfactant fluid and 3 wt% HCl acid. Flooding experiments were conducted for core samples from the Eagle Ford outcrop to measure the brine permeability, time of breakthrough and water relative permeability. The measurements were performed for intact samples and also after flooding the samples with the fracturing fluids. A simulation sector modeling for a hydraulically fractured vertical well in the shale formation was constructed to investigate the effect of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. A sensitivity analysis was considered to study the effect of the formation capillary pressure and reservoir pressure on the fluid flowback and fluid loss due to counter-current capillary imbibition. The study results showed that the fluid saturation in the near fracture face shale matrix is highly reduced by the effect of the high capillary pressure. Therefore, the fluid had not flow back from the near fracture face matrix. Moreover, adding a non-ionic surfactant to the friction reducer pad fluid or using 3 wt% HCl increased the fluid loss during pumping and the fluid imbibition during shut-in, flowback, and production. Therefore, the dilute HCl acid and small well shut-in times are recommended when no flowback occurs from the near fracture face matrix due to low fluid saturation. The fluid loss from the near fracture face region due to counter-current capillary imbibition reduced the effect of the fluid saturation on the gas production. However, the high fluid saturation and the polymer adsorption may cause water blocks. Thus, reducing the gas production or leading to a complete gas block. For shales with moderate capillary pressure, a flowback from the near fracture face matrix has occurred. Hence, the friction reducer with a non-ionic surfactant fluid and 3 wt% HCl enhanced both of the fluid loss due to counter-current capillary imbibition and the fluid flowback. However, a non-ionic surfactant and long shut-in time are recommended for the hydraulic fracturing. Shales with low reservoir pressure had less fluid flowback and more fluid loss. To minimize the fluid loss during pumping and to overcome the water block problem, it is recommended to use a friction reducer fluid in the pad stage while injecting a non-ionic surfactant or dilute acid during the subsequent fracturing steps.

The present study used the workflow presented in Al-Ameri et al. (2018a, 2018b) to evaluate the impact of the fracturing fluid imbibition on the near fracture face shale matrix. Al-Ameri et al. (2018b) used carbonate-rich outcrop shale core samples that had very low and no clay content. However, in this workflow, core samples from the Barnett reservoir that had an abundant amount of quartz and clay were used. The primary aspect of the current study is to investigate the mutual effect of the shale rock petrophysical properties and the polymer adsorption; moreover, the effect of the shale mineralogical composition on the rock prone to adsorb polymer. The effect of the non-ionic surfactant on the imbibition rates, and also the anisotropy on the rock ability for polymer adsorption were also investigated. The results of this workflow were compared to the Marcellus samples results presented in Al-Ameri et al. (2018b). The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup. The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition. Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales. The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation. The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.

In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation are integrated to quantify the changes in the effective water permeability, capillary pressure and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated. The researchers considered a spontaneous imbibition of a 0.1 wt% friction reducer fluid into low-permeability sand core samples extracted from Scioto, Crab Orchard, and Kentucky outcrops. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using distilled water, friction reducer fluid, and distilled water again. Prior to each experiment, the core sample was cleaned with toluene and then dried completely. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus. The results showed that the polymer adsorption throughout the fracturing fluid spontaneous imbibition significantly reduces the water spontaneous imbibition volumes. Moreover, the polymer adsorption effect increases as the porosity increases. The results showed also that the effective water permeability is decreased because of the polymer adsorption effect. The Residual Resistance Factors calculated from the spontaneous imbibition experiments are in agreement with the values calculated from the constant rate permeability measurements. Adding surfactant to the pad stage- friction reducer fluid increases its spontaneously imbibed (leak-off) volumes. The results showed also that the effect of polymer adsorption on the imbibition rates is significantly less when the rock-fluid contact surface is parallel to the bedding plane. The imbibition potentials were calculated before and after polymer adsorption. Since the water permeability was calculated independently, the capillary pressure curves were calculated from the imbibition potentials. The results showed polymer adsorption leads to a slight increase in the capillary pressure. The spontaneous imbibition experiment is numerically simulated using ECLIPSE commercial simulator and the imbibition water relative permeability curves were calculated by matching the results to the water spontaneous imbibition experimental data. The results showed that the polymer adsorption significantly reduces the water relative permeability curves for Scioto and Crab Orchard.

A Residual Oil Zone (ROZ) is a naturally waterflooded reservoir at residual or near residual oil saturation, technically recoverable only through unconventional methods. The development of ROZs is extensively pursued in the Texas Permian Basin. Several successful ROZ CO2 Enhanced Oil Recovery (CO2-EOR) projects indicate enormous resource potential for these emerging oil plays. Another approach, called Depressurizing the Upper ROZ (DUROZ), was recently proposed and is currently under extensive investigation. This study offers a mechanistic understanding of DUROZ and investigates the factors affecting its viability and performance. DUROZ refers to the progressive reduction of reservoir pressure through the withdrawal of large volumes of water from a horizontal well in the upper section of ROZ. When reservoir pressure falls below the saturation pressure, gas bubbles liberate from capillary-trapped oil and develop into a continuous gas phase. Consequently, the oil phase may also become mobile beyond waterflood residual oil saturation. We history-match the oil and water production from twoDUROZ producers in the upper San Andres dolomite using a tuned reservoir simulation model. To properly capture the rock and fluid interaction, the relative permeability data are tuned with the experimental core datafrom the San Andres ROZ. Extensive experimental studies have highlighted a substantial difference between relative permeabilities measured under external drive and solution gas drive. We define two sets of relative permeabilities: an original set based on the external drive experiments and the relevant correlations, and a modified set for modeling production under solution gas drive. Our results show that even for the most optimistic relative permeabilities, the reservoir initial oil saturation should be at least 20% above the residual oil saturationin order to match the oil cuts of the reported DUROZ producers. This shows inconsistencies in use of the term "residual oil"zone by the industry in the Permian Basin. In other words, although DUROZ shows potential for production beyond waterflood residual oil saturation, the documented cases are unlikely to be true ROZ producers and are more likely completed in the Transition Zone (TZ) or near-ROZ. Finally, a discussion on the operational risks and technical considerations associated with DUROZ, including water disposal, infrastructure and facility requirements, and modeling limitations, is presented.

Thirty-five cement samples were tested in an Ultrasonic Cement Analyzer (UCA) at varying curing conditions and for varying curing times, and then uniaxially compressed to failure in a hydraulic press. An attempt was made, using the ultrasonic transit time data measured with a UCA and the uniaxial compressive strength data measured using a hydraulic press, to derive an empirical model capable of accurately predicting uniaxial compressive strength from the ultrasonic transit time. Using the Levenberg-Marquardt algorithm, the experimental data was fit to two models. In addition to the transit time dependence, the first model presented incorporates a term that accounts for the curing time while the second model contains terms that account for both the curing time and cement composition. The results obtained illustrate the complexity of deriving a correlation with general applicability to all well cements. The best performing model based on both curve fit error and prediction performance for the samples tested was the model that accounted only for the curing time dependency of the cement strength development rate in addition to the measured transit time, indicating that the transit time measurement history is sufficient as a tool for characterizing well cement strength development.

Single probe formation testers are widely used tools in the oil industry for collecting fluid samples and measuring pressure transients to estimate initial formation pressure. Although in principle pressure transient data can be used to estimate formation permeability based on drawdown and buildup analyses, the permeablity estimated is rarely used in reality since these estimation methods are based on a single-layer or homogeneous reservoir which is rarely the case. There are many probe test data available in the industry. If we can use these data to estimate permeabilities from every location the tool is stopped and upscale these permeabilities to predict the well productivity index (PI) for the whole multilayer reservoir, then these pressure transient data become very valuable. This can save the cost of or completely replace expensive well tests. In this paper, we study the effect of the distance of outer layers on permeability estimation in multilayer reservoir systems. We first investigate the effective radius of drawdown and buildup tests of a typical probe test in a multilayer reservoir. Then we define a dimensionless parameter to present this effective radius. This dimensionless parameter is a function of permeability and the distance from the probe to the outer layer. Within this effective radius, the permeability may be estimated within an acceptable engineering error. A new method is proposed to estimate the well productivity of a multilayer reservoir from single probe tests. The estimated well productivity is compared with that from the conventional well tests using simulated data as well as actual test data. The productivities from our test analysis technique and other approaches are acceptably close. Therefore, this effective dimensionless radius may be used to guide the selection of test locations so that the test data can be used later to estimate the PI of a well.

Cyclic gas injection is considered as an effective and quick responding recovery process that has been widely used in the worldwide. Studies showed that cyclic gas injection combined with modern technologies such as horizontal well drilling and hydraulic fracturing has achieved promising results in low permeability formation. Cyclic gas injection technique was introduced in our earlier publication for improving oil recovery in stimulated fractured shale oil reservoirs. In this paper, we focus on the effect of injected gas composition and fracture properties on oil recovery. Different injection gas scenarios such as lean gas, rich gas and CO2 were included in the simulation in order to analyze the EOR mechanisms of vaporizing, condensing or a combined condensing/vaporizing process. Our simulation results indicate that the stimulated natural fractures are critical to enhancing oil recovery and well productivity performance in shale oil reservoirs. Since the interaction of the induced hydraulic fractures with pre-existing natural fractures and fissures makes the hydraulically fractured reservoir modeling very challenging in shale oil/gas reservoirs, we can use a dual-continuum model by making changes to the fracture permeability and intensity to attain a better characterization of the natural fractures. We conclude that cyclic gas injection in shale oil reservoirs employing hydraulically stimulated fractures is feasible to improve substantial amounts of oil production than primary production.

Low oil recovery in shale oil reservoirs and vast shale reservoir volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. A recent numerical study has indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs, and gas channeling can be mitigated. This paper presents our experimental verification and quantification of the potential to improve oil recovery by cyclic gas injection in shale oil reservoirs. Core plugs of Barnett, Marcos and Eagle Ford shales were used. The oil used was Mineral oil (Soltrol 130) and the gas used was Nitrogen. Unfractured cores were used in the experiments. The effects of cyclic time and injection pressure on oil recovery, among other parameters, were investigated. Our results also showed that cycle gas injection could increase the recovery from 10 to 50% depending on the injection pressure and shale core type. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase. The cyclic gas injection provides an effective and practical method to improve oil recovery in shale reservoirs because the gas needed is available in liquid-rich shale plays.

The Barnett shale is a renowned Resource play and one of the most developed in North America with enormous hydrocarbon potential located in the Fort Worth basin of North Central Texas. It is currently the largest producing natural gas field in the United States, averaging 5.5 Bcf/d and cumulative production of 9 Tcf as at the end of 2010. However, in spite of its success, it is difficult to predict well performance and reserves with certainty largely due to geological complexity and completion type. Thus, it is common to see wells in the same producing interval exhibiting large differences in producing rates and estimated ultimate recoveries (EUR). Peak monthly rate (PMR) has been found to be quite useful by some operators in predicting gas reserves because of its favorable correlation with EUR. In this paper, 2,932 Horizontal gas wells were sampled from the top six producing counties in the area and analyzed to confirm if peak month rate can be a good predictor of gas reserves by determining its correlation with EUR. Also, the P10/P90 ratios were assessed for both EUR and PMR. P10/P90 ratios have been found useful in measuring uncertainty in performance and were used extensively in this work to analyze and compare performance of wells across the six counties studied. In addition, P10/P90 ratios can be an indicator of proper population size for use in probabilistic analysis with the given data set. Most of the counties proved to have an ample data set for probabilistic use. Since geological complexity and completion efficiency are common features affecting performance in resource play reservoirs, several parameters such as: Reservoir depth, Gross thickness, BTU content and Lateral length were reviewed and analyzed with respect to its effect on performance in the Barnett shale.

There is considerable interest in detecting objects such as landmines shallowly buried in loose earth or sand. Various techniques involving microwave, acoustic, thermal and magnetic sensors have been used to detect such objects. Acoustic and microwave sensors have shown promise, especially if used together. In most cases, the sensor package is scanned over an area to eventually build up an image or map of anomalies. We are proposing an alternate, acoustic method that directly provides an image of acoustic waves in sand or soil, and their interaction with buried objects. The INEEL Laser Ultrasonic Camera utilizes dynamic holography within photorefractive recording materials. This permits one to image and demodulate acoustic waves on surfaces in real time, without scanning. A video image is produced where intensity is directly and linearly proportional to surface motion. Both specular and diffusely reflecting surfaces can be accommodated and surface motion as small as 0.1 nm can be quantitatively detected. This system was used to directly image acoustic surface waves in sand as well as in solid objects. Waves at frequencies of 16 kHz were generated using modified acoustic speakers. These waves were directed through sand toward partially buried objects. The sand container was not on a vibration isolation table, but sat on the lab floor. Interaction of wavefronts with buried objects showed reflection, diffraction and interference effects that could provide clues to location and characteristics of buried objects. Although results are preliminary, success in this effort suggests that this method could be applied to detection of buried landmines or other near-surface items such as pipes and tanks.

The INEEL has developed a photorefractive ultrasonic imaging technology that records both phase and amplitude of ultrasonic waves on the surface of solids. Phase locked dynamic holography provides full field images of these waves scattered from subsurface defects in solids, and these data are compared with theoretical predictions. Laser light reflected by a vibrating surface is imaged into a photorefractive material where it is mixed in a heterodyne technique with a reference wave. This demodulates the data and provides an image of the ultrasonic waves in either 2 wave or 4 wave mixing mode. These data images are recorded at video frame rates and show phase locked traveling or resonant acoustic waves. This technique can be used over a broad range of ultrasonic frequencies. Acoustic frequencies from 2 kHz to 10 MHz have been imaged, and a point measuring (non-imaging) version of the system has measured picometer amplitudes at 1 GHz.

A new approach to the measurement of ultrasonic vibrations has been developed at the INEEL. This system utilizes heterodyne interferometric detection in a photorefractive material to provide real time, full field images of ultrasonic vibration amplitude and phase without scanning. The INEEL Laser Ultrasonic Camera has linear response for ultrasonic displacement (xi) < (lambda) divided by 4(pi) , approximately 45 nm displacement at a laser wavelength of 532 nm. In addition, the system exhibits flat response and narrow band detection for a broad range of vibration frequencies. The system is very robust, and has the potential for operation even in noisy industrial settings. A description of the system, representative data and several potential applications will be presented.

Anisotropic properties of materials can be determined by measuring the propagation of elastic waves in different directions. A laser imaging approach is presented that utilizes the adaptive property of photorefractive materials to produce a real-time measurement of the antisymmetric Lamb or flexural traveling wave mode displacement and phase. Continuous excitation is employed and the data is recorded and displayed in all directions simultaneously at video camera frame rates. Fourier transform of the data produces an image of the wave slowness in all planar directions. The results demonstrate imaging of microstructural isotropy and anisotropy and stress induced ansiotropy in plates.

Anisotropic properties of sheet materials can be determined by measuring the propagation of Lamb waves in different directions. Electromagnetic acoustic transduction and laser ultrasonic methods provide noncontacting approaches that are often desired for application to industrial and processing environments. This paper describes a laser imaging approach utilizing the adaptive property of photorefractive materials to produce a real-time measurement of the antisymmetric Lamb wave mode in all directions simultaneously. Continuous excitation is employed enabling the data to be recorded and displayed by a CCD camera. Analysis of the image produces a direct quantitative determination of the phase velocity in all directions showing plate anisotropy in the plane.

Tight oil reservoirs have become one of the main forces of oil production growth in the USA. Only 3% to 7% of the oil can be recovered under primary depletion. Further improvement in oil recovery in tight oil reservoirs can be achieved by applying gas flooding or huff ‘n’ puff. However, these methods have limitations, especially when dealing with ultra-low permeable formations. Hence, the objective of this study was to discover the limitations of EOR methods in tight formation. A 2D compositional simulation model was used to investigate the limitations of applying gas flooding and huff ‘n’ puff in a tight formation. The results were compared under distinct scenarios and conditions. Distinct values of well spacing were used to identify the optimal well spacing. Different average permeability values were used to study the effect of permeability value on the EOR performance in tight formation. The Simulation Model results showed a potential of applying EOR in tight formation under specific conditions. Well spacing optimization has a significant effect on the gas flooding performance in tight formations. Hence, it is recommended to identify the well spacing before commencing gas flooding or huff ‘n’ puff. This simulation study showed any formation with a permeability less than 0.01 md should not be considered for gas flooding due to gas injectivity issues, long injection time, and long depletion time. Huff ‘n’ puff showed better results and more oil recovery at a permeability less than 0.01 md. Simulation results showed that any formation with a permeability greater than 0.1 md may be considered for gas flooding because of the following reasons: gas flooding showed a better recovery factor compared to the huff ‘n’ puff method; short depletion time was needed to start gas injection; and gas flooding required less injection time and provided long well spacing. This study increases understanding of the EOR factor in a tight formation. The results of the study showed the limitations of the EOR using simulation approaches. Knowing the disadvantages and limitations of EOR in tight formations will lead to improving the efficiency of EOR in tight formations.

Complete zonal isolation along with wellbore integrity is paramount to oil field development which ensures environmental safety and favorable well economics. However, the complexity of wells today increases the wellbore architecture's susceptibility to unavoidable stress events. This research focuses on utilizing aluminum oxide nanofibers (ANF's) in oil well cements. ANF's are a relatively new type of composite nanomaterial that has the potential to provide significant mechanical performance. A Scanning Electron Microscope (SEM) was used to study the morphology of ANF's. Nanofibers were ultrasonicated in water and characterized quantitatively by ultraviolet–visible spectrophotometry (UV-Vis) and qualitatively by transmission electron microscope (TEM) images. The results show ANF's have high dispersibility. Cement class "H" formulations containing different percentages of ANF's by weight of cement (BWOC) were mixed and cured with various additives for 24 hours at 76.7 °C with 24.13 MPa. Uniaxial compressive strength (UCS) tests were performed which suggested the inclusion of ANF's increases the UCS when compared to cement samples without ANF's. Although, high concentrations of ANF's results in nanofiber agglomeration which weakens the mechanical properties of the cement samples. The elastic properties of the cement samples were measured under cyclic confining pressures. All cement samples experienced low inelastic deformation during confining pressure cycling. Samples containing 0.1% ANF's BWOC possessed the lowest Modulus of Elasticity (MOE) and the highest Poisson's Ratio. This increases the cement sheath's chances of resisting deformation due to casing contraction/expansion. An X-ray diffraction (XRD) analysis was conducted to determine the hydration products. All cement formulation experienced the same XRD pattern with only variations in the diffraction peaks. Cement samples containing ANF's contained increased amounts of calcium silicate hydrate (C-S-H) gel due to the nucleation effect and the formation of tobermorite.