bluuebunny/crossref_metadata_2025 huggingface dataset:
The Successful Application of Customized Fluids System to Effectively Bridge Across Extreme Overbalance Conditions – Case Histories from Saudi Arabian Field.
Authors: Maley Iain , Jadhav Prakash , Everhard Ian L. , Addagalla Ajay , Hassan Mohammad Omran , Kosandar Balraj
Published: October 2017

Drilling lateral re-entry gas wells in the Eastern Province of Saudi Arabia has become a serious challenge with casing string design limitations leading to excessive overbalance pressures of over 5,450 psi across highly permeable Carbonate (Limestone and Dolomite) formations. The challenges associated with drilling these re-entry build up sections are as below -

Salt water influxes through the Jilh formations Expected severe losses across Khuff A and B formations High density fluid management issues with losses and influx situations Differential sticking across low pressure formations Wellbore instability across the overlying Sudhair reactive shale High angle section profiles (> 60° inclination).

A customized fluid system was designed to overcome the above challenges associated with high overbalance pressure, targeting improved bridging, minimizing pore pressure transmission and increasing wellbore strengthening with increased hoop stress techniques.

Software modelling and permeability plugging tests were performed to evaluate the fluid behavior under downhole conditions and to simulate the characteristics of induced micro fractures. Porosity, permeability and the likelihood of micro fracturing were considered to optimize the bridging mechanism and materials. These results identified a synthetic deformable sealing polymer combined with sized synthetic graphite and ground marble which showed considerable improvement in minimizing spurt and overall filtrate loss with minimum effect on the rheological parameters and stability of the fluid system.

This paper describes the customized drilling fluids performance in two study wells as compared to offset wells. A comprehensive engineered approach addressed the challenges of drilling in such extreme overbalance conditions by using a revolutionary bridging technology. The lessons learned on these wells have been incorporated while drilling subsequent wells to continue to improve performance.
Innovative Solutions to Creating an Accelerated Training & Development Program for Technical Field Personnel
Authors: Robert Seth , Fiffick William , Guillory Robert
Published: October 2017

The following case study details how a major equipment manufacturer accelerated the training and development of new field service technicians. As the drilling industry recovers from a significant downturn, many companies are challenged to devise better programs to quickly train and develop employee competency so that the increased skill demands can be satisfied.

In 2014, an accelerated program was developed, providing training and development that would normally take over a year, and reducing that timeframe to less than six months. The three-phased approach included formal classroom training, field based training, along with mentoring and coaching. Leveraging the existing competence assurance management system, a custom program was developed to cover 3 distinct product lines. Training was not only technically based, but was also included soft skills training such as customer service training, safety training, and mentoring from Senior Management.

The resulting accelerated program was executed for three groups of field technicians, each graduating within the prescribed six month timeframe. Each delegate achieved the targeted competency level of at least 2.1 (on a scale of 1.0 – 4.3). Management was able to reinforce the safety culture and core mission of the organization to each of these employees throughout the program. The company was able to track trainee progress, manage, and successfully coach the delegates throughout the program. Training focused on real world scenarios, helping Field Service Technicians to practice the use of various resources and tools available to learn better troubleshooting skills.

As the oilfield recovers from one of the largest downturns in history, the ability to successfully attract, train and retain qualified technicians will be crucial. Organizations that can successfully manage accelerated development programs will realize benefits in reducing training time, improving standardization and job quality, as well as a modeling of a better safety culture.
Using Data Analytics on Dimensionless Numbers to Predict the Ultimate Recovery Factors for Different Drive Mechanisms of Gulf of Mexico Oil Fields
Authors: Talluru Gowtham , Wu Xingru
Published: October 2017

The ultimate recovery factor is strongly affected by petrophysical parameters, engineering data, structures, and drive mechanisms. The knowledge of the recovery factor is needed for multiple decision makings and it should be known in the whole development process. This study is to estimate the recovery factor from a different perspective with traditional methods.

Using development data from the Gulf of Mexico, this study explores parametric relationships between different reservoirs using data analytics. Given that there are hundreds of attributes to characterize a reservoir, and some of the records in a database may not be accurate or contradictory to each other, we use dimensionless parameters to categorize reservoirs based on similarity theorems. Using dimensionless parameters not only reduces the number of variables for data analytics, but they have physical meanings which make them easily applicable to different scenarios. This research presents a comparative study of different data mining techniques and statistical significance of various geological, reservoir and engineering parameters.

This dataset consists of 4000 oil reservoirs and each reservoir has 82 attributes. Initial data cleaning was carried out on this dataset to remove reservoirs with erroneous data entries. Dimensionless reservoir parameters are defined and used for the study to make the models consistent to other reservoirs. In the model development, 80% dataset was used to train the model and the rest dataset was used to evaluate the trained models. A few models based on their intrinsic design predicted the ultimate recovery factor with an error of 8-9%, and a few other models predicted the same with an error of 10-12%. Ensemble of a few models predicted oil recovery factor with an error of 6%. In addition to predict ultimate recovery factor, relative importance of various dimensionless parameters, and sensitivity of ultimate recovery factor to reservoir and engineering parameters were studied. This kind of study uses already available reservoir data and model to provide a quick means to evaluate new oil reservoirs even with limited data.
A New Approach to Harness Data for Measuring Invisible Lost Time in Drilling Operations
Authors: Lakhanpal Vikrant , Samuel Robello
Published: October 2017

Drilling operations can include invisible lost time (ILT), within productive time and nonproductive time (NPT). ILT is the time lost because a portion of the drilling operation is not performed at maximum efficiency. Current industry techniques use subjective decision making to calculate NPT, which only illustrates that ILT is present and does not address the root cause.

By considering the dynamic downhole conditions and comparing the time necessary for various personnel to perform the same operations, a threshold time can be calculated for each operation, which is used to calculate NPT.

After NPT is calculated, the real-time drilling data are converted to segmented drill-time data [i.e., the time necessary for each activity (Δt)] to convert to a time-series analysis problem. The algorithm developed decomposes the obtained time series into its intrinsic mode functions (IMFs) using the ensemble empirical mode decomposition (EMD), which tolerates residual noise in the signal. Mode mixing is a significant issue when the drilling data are converted into a time-series problem. Hence, an energy conservation principle is presented to identify and help eliminate the false mode components; thereby, only the components that truly represent the drilling activities are used for further calculations. The true characteristic IMFs are then combined with their weights to obtain a modified Δt series, which represents ILT. The weight estimation process is performed automatically to maximize the kurtosis and entropy of the Δt series. The NPT is calculated again from the modified Δt series using the technique previously described. The new NPT provides a higher value of NPT from which ILT can be computed using simple subtraction.

After ILT is identified and calculated, the ILT cause can be ascertained by analyzing the drilling parameters, such as rate of penetration (ROP), weight on bit (WOB), torque, and flow rate, using an algorithm similar to the one previously discussed.

The proposed method can be integrated with future management and well design plans to help improve drilling operation efficiency. The proposed workflow automates the entire calculation process, thereby reducing human interference and maximizing the time value of information.

Additionally, this paper proposes another simpler analysis tool that is based on pattern analysis of the final IMF obtained from the decomposition of a time series. This observation-based tool proposes that if a process is nonproductive, then the final IMF will have a downward parabolic trend. If the personnel performance is consistent, then the final IMF will have an upward parabolic trend.

This paper presents four field case studies to help prove the hypothesis of this work.
Low Salinity Water Injection: Effect of Acid and Base Functionality on Recovery Performance
Authors: Miyauchi Tomás Eduardo , Lu Yingda , Firoozabadi Abbas
Published: October 2017

Injection of low salinity water in some crude-rock systems may provide substantial improved oil recovery. However, the mechanisms are not fully understood. There is not much understanding of what type of crudes or what type of rocks lead to improved oil recovery from low salinity water injection. In this work, we measure acid and base functionality of the crude oil as well as brine-crude oil interface viscoelasticity and contact angles to shed light on low salinity water injection in sandstone rocks. We use three different crude oils from three different reservoirs from the Middle East. Two of the oils are heated to 55 °C to remove some of the light components to broaden the range of oil variables. We carry high salinity and low salinity water injection in Berea sandstone cores saturated with the whole crudes and the heated crudes. In some tests after high salinity water injection, we perform low salinity water injection. All rock/brine/crude systems examined show water wetting conditions. In one of the three whole crudes, we observe a significant improved recovery from 53% to 66% with low salinity water injection. In another whole crude, there is no increase in recovery with low salinity water injection. In the third whole crude, there is limited improved recovery with low salinity water injection. In the heated crude oils (with removal of light components) the recovery is improved significantly by low salinity water injection. Various measurements show that total acid number and total base number as well as the interface viscoelasticity contribute to improved oil recovery from low salinity water injection in a water-wetting state. Our data also show very little improved oil recovery when low salinity brine is injected after injection of high salinity brine. In our measurements, the pH of the produced water in the sandstone is about 10. It does not depend on the salinity of the injected brine.
Improving Chemical EOR Simulations and Reducing the Subsurface Uncertainty Using Downscaling Conditioned to Tracer Data
Authors: Torrealba Victor A. , Hoteit Hussein , Chawathe Adwait
Published: October 2017

Recovery mechanisms are more likely to be influenced by grid-block size and reservoir heterogeneity in Chemical EOR (CEOR) than in conventional Water Flood (WF) simulations. Grid upscaling based on single-phase flow is a common practice in WF simulation models, where simulation grids are coarsened to perform history matching and sensitivity analyses within affordable computational times. This coarse grid resolution (typically about 100 ft.) could be sufficient in WF, however, it usually fails to capture key physical mechanisms in CEOR. In addition to increased numerical dispersion in coarse models, these models tend to artificially increase the level of mixing between the fluids and may not have enough resolution to capture different length scales of geological features to which EOR processes can be highly sensitive. As a result of which, coarse models usually overestimate the sweep efficiency, and underestimate the displacement efficiency. Grid refinement (simple downscaling) can resolve artificial mixing but appropriately re-creating the fine-scale heterogeneity, without degrading the history-match conducted on the coarse-scale, remains a challenge. Because of the difference in recovery mechanisms involved in CEOR, such as miscibility and thermodynamic phase split, the impact of grid downscaling on CEOR simulations is not well understood.

In this work, we introduce a geostatistical downscaling method conditioned to tracer data to refine a coarse history-matched WF model. This downscaling process is necessary for CEOR simulations when the original (fine) earth model is not available or when major disconnects occur between the original earth model and the history-matched coarse WF model. The proposed downscaling method is a process of refining the coarse grid, and populating the relevant properties in the newly created finer grid cells. The method considers the values of rock properties in the coarse grid as hard data, and the corresponding variograms and property distributions as soft data. The method honors the fluid material balance and geological features from the coarse model. A workflow is outlined to address uncertainties in geological properties that can be reduced by integrating dynamic data such as sweep efficiency from interwell tracers. We provide several test cases and demonstrate the applicability of the proposed method to improve the history-match of a chemical EOR pilot. Further, we evaluate the fitness of different heterogeneity measures for grid-ranking of CEOR processes.
A New Approach to Determine Asphaltenes Stability
Authors: Hascakir Berna
Published: October 2017

Asphaltenes stability is a phase behavior phenomenon and affected mainly by the change in pressure and temperature. However, the changes in pressure and temperature lead compositional changes, hence, the dependency of asphaltenes stability on crude oil composition requires more clarity. In this study, the impact of solubility, polarity, and reservoir rock composition on asphaltenes stability for 11 different crude oil samples were investigated. All crude oil samples used in this study due to their high viscosity and low API gravity were classified as heavy oil, extra-heavy oil, and bitumen. Samples were first separated to their Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions. Based on the obtained weight percent of SARA fractions, solubility of asphaltenes in crude oil fractions was determined through Colloidal Instability Index (CII). Polarity of the crude oil samples was indirectly defined by dielectric constant measurements. Finally, the asphaltenes fractions was mixed with deionized water and then the supernatant samples were analyzed in terms of Total Dissolved Solids (TDS) and zeta potential to observe the possible interactions between reservoir rock and crude oil. Our results suggest that reservoir rock-crude oil interaction affects most the asphaltenes stability. Moreover, this interaction has positive impact on maintaining asphaltenes stability. As the asphaltenes interact more with the reservoir rock, in general, asphaltenes surfaces become negatively charged, consequently, the electrostatic repulsions created by the reservoir rock components attached to the asphaltenes surfaces keep the asphaltenes clusters apart. If the inorganic-organic interaction (reservoir rock and crude oil interaction) is insignificant, then, asphaltenes stability is determined by polarity and solubility.
Monitoring and Improvement of Waterflooding Sweep Efficiency Using Pressure Pulse Testing
Authors: Shakiba Mahmood , Hosseini Seyyed A. , Sepehrnoori Kamy
Published: October 2017

During waterflooding, formation heterogeneity controls water sweep efficiency. The location of water-injection wells and operational parameters should be designed based on the heterogeneity of the formation in order to maximize oil production and to avoid early water breakthrough. However, initial geologic and reservoir characterization studies may not provide an accurate view of the location of high-perm zones, channels, and fractures. In this study, we present the application of multi-well pressure pulse testing in the dynamic monitoring of waterflooding sweep efficiency and in the investigation of interwell connectivity. In a pressure pulse test, a periodic injection-rate signal comprising a series of active and shut-in cycles is superimposed on the regular schedule of a candidate injection well, and the corresponding pressure response is recorded at several surrounding wells. Because of the periodic characteristic of the pressure pulse test, pressure response at observation wells can be extracted from background reservoir pressure data; therefore, no well shut-in is required during the test. Pressure data are then transformed into the frequency domain using fast Fourier transform (FFT). Finally, using a modified analytical solution in the frequency domain, the hydraulic diffusivity coefficient is obtained. The modified analytical solution only takes pressure data at the pulsing well and the observation well; no injection-rate data is required in the analysis.

We verified the accuracy of pressure pulse testing using a waterflooding case in an inverted five-spot well pattern. The measured hydraulic diffusivity from pulse testing was in agreement with the hydraulic diffusivity coefficient calculated from formation properties. In the next step, we applied pressure pulse testing in a five-spot well pattern with a channel between one of the well pairs. Again, time-lapse analysis of the hydraulic diffusivity coefficient successfully identified the direction of the high-permeability channel, which helped prevent an early water breakthrough. In the last simulation case study, we investigated pressure pulse testing in a synthetic field-scale waterflooding project. We considered a lognormal permeability distribution to mimic formation heterogeneity. Using the information derived in this step, the zones with higher water invasion were determined, which led to modification of well operational parameters such as injection rate and bottom-hole pressures. Optimization of waterflooding design significantly improved sweep efficiency and increased the recovery factor of the process. Pressure pulse testing reasonably predicted the heterogeneity of the formation through interwell hydraulic diffusivity coefficients. Such information substantially assists in future planning and development of the formation.
Hindered Transport in Nanoporous Unconventional Reservoirs and Its Implications on IOR and Stimulation
Authors: Huseynova Jamila , Ozkan Erdal
Published: October 2017

This paper focuses on steric filtration of hydrocarbon mixtures in nanoporous media. Molecular filtration is described by molecular partitioning between the bulk and nanopore phases. For the hindered transport of solid particles through porous material, filtration efficiency is defined based on the ratio of the solute and pore channel dimensions. This approach is not suitable for hydrocarbon mixtures because of the dependence of molecular size and shape on thermodynamic conditions. In this work, partition coefficient is determined from equilibrium thermodynamics. Flash calculations are performed to determine the fugacity ratio and the corresponding compositions of hindered components when the unhindered hydrocarbons reach equilibrium after a change in the system pressure. The differences between the original and final pressures is the filtration pressure. Two- and three-component hydrocarbon mixtures are considered with the heaviest component being the hindered component. The effect of temperature and pressure on filtration efficiency is documented and implications on improved recovery from unconventional reservoirs are discussed. According to the results filtration efficiency decreases (more hindered components pass through the pore throat) as the filtration pressure increases and ambient temperature decreases.
Shifting Turner's Paradigm: Gas Wells Can Produce in Slug Flow
Authors: Marino M. , Schiferli W. , Veeken C. A. , Smith J.
Published: October 2017

This paper aims at improving the understanding of gas wells stability and to shift Turner's paradigm, i.e. to demonstrate that, under specific circumstances, stable production below the liquid loading rate in the slug flow regime is feasible. Field examples are presented together with modelling results that highlight how stable slug flow gas production can be sustained and promoted.

The new approach to evaluate well stability is based on conventional nodal analysis, but makes use of a total pressure drop curve rather than only looking at the well. This curve includes the wellbore, the choke and – in very tight reservoirs – the pressure drop over the near-wellbore reservoir. The minimum in this combined pressure drop curve yields the minimum flow rate for well stability. This method was applied and tested on several gas wells. Examples include two gas wells with drawdown limitations, one to avoid halite precipitation and one to reduce sand production, and a very tight gas well. Both steady state nodal analysis and dynamic simulators were used.

Whereas a conventional nodal analysis indicated that stable production was not possible since the inflow performance curve and tubing performance curve did not intersect right of the minimum, the total pressure drop curve correctly predicted that these wells could flow continuously below their conventional critical rate. For the wells with drawdown limitations, this meant being able to further choke back the wells to mitigate halite precipitation and sand production, de facto extending the well production life and reducing operational intensity. For the tight gas well, this meant improving forecasting of a well for which intermittent production was deemed necessary. In conclusion, in cases where a choke or tight reservoir adds significant pressure drop, well stability is found to be dictated by the total pressure drop curve. This improved analysis can yield more accurate production forecasts and prevent unnecessary interventions.

The innovative total pressure drop curve presented in this paper shifts a paradigm set by Turner in 1969: gas wells can now produce in slug flow. Furthermore, the fact that this methodology uses the existing and well known nodal analysis will simplify its wide diffusion and implementation.
Inverted ESP Changing the Game in Water Coning Control in Water Drive Reservoirs - North Kuwait Case Study
Authors: Anthony E. , Elaila S. , Al-Maqsseed N. , Areekat M.
Published: October 2017

Water Coning is a reservoir phenomenon that is particularly more challenging in reservoirs where Kv/Kh > 0.5. To maximize production rates and ultimate hydrocarbon recovery from its water drive reservoirs, North Kuwait shifted its exploitation strategy from vertical to horizontal completions. When water broke through, however, remedial efforts were limited, complex, and certainly short-lived since the water moves laterally along wellbore to adjacent compartments. A more effective solution to control the water cone was implemented in a vertical well with good success, but with some operational limits. This completion used a conventional ESP with Y-tool to create a counteractive pressure drawdown just below the Oil/Water contact in an effort to limit the progression of the water cone. The major limitations with this ESP configuration were casing size (can only be used in 9⅝" casings and larger), and rate restrictions (limited to 4,500 BPD injection rate, beyond which shroud erosion is expected). Cone Control technology, is to create a pressure drawdown (ΔP), just below the OWC marginally more than the ΔP across the perforated interval within the Oil leg. This drawdown retards the progression of the water cone, and can best be achieved using an inverted, bottom-discharge high-volume ESP. Inverted ESPs were selected after the limited success achieved from utilizing a shrouded conventional ESP with Y-tool in the original Cone Control completion. Inverted ESP’s eliminated both constraints, and added the advantage of being shorter and more compact, suitable for wells with higher dogleg severities. The Inverted ESP is used for subsurface disposal, and can be injected into an underlying hydrocarbon-free aquifer, or reservoir requiring pressure support.
System Density of Oil-Gas Mixtures: Insights from Molecular Simulations
Authors: Mehana Mohamed , Fahes Mashhad , Huang Liangliang
Published: October 2017

Gravity segregation of reservoir fluids is mainly controlled by system density. While most of the gases used in the field for the purpose of Enhanced Oil Recovery (EOR) result in a reduction in system density, Carbon Dioxide (CO2) can result in an increase of the mixture density upon mixing. Experimental observations confirmed this behavior. In addition, field operations report an early breakthrough for CO2 flooding, which is related to the associated gravity segregation due to the abnormal density behavior. However, the molecular interactions at play that have an impact on the observed macroscopic behavior have not been well-understood or deeply investigated. Molecular simulation of methane, propane and carbon dioxide mixtures with octane, benzene, pentane and hexadecane are studied up to the miscibility limit at temperatures up to 260 °F (400 K), and pressures up to 6000 psi (400 bar). There is a proximity between the molecular simulation predictions of the physical properties and those obtained through experimental work and EOS. It is evident that oil-CO2 mixtures sustain their system density to a higher gas mole percent compared to other gases, with the system density in some cases exceeding the pure liquid hydrocarbon density even when gas density at those conditions is lower. Our results have demonstrated that the intermolecular columbic and induced dipole interactions, and the stretching of the alkane molecules, the proposed mechanisms in literature, might not be the key to understanding the oil-CO2 density behavior. However, the molecular size of the gas seems to play an important role in the density profile observed.
A Generalized Derivative-Free Rate Allocation Optimization for Water and Gas Flooding Using Streamline-Based Method
Authors: Tanaka Shusei , Kam Dongjae , Xie Jiang , Wang Zhiming , Wen Xian-Huan , Dehghani Kaveh , Chen Hongquan , Datta-Gupta Akhil
Published: October 2017

Rate allocation optimization for water and gas injection/production processes is typically complex, requiring multiple simulations to find the optimal reservoir management strategy for improved economic value of the asset. The objective of this paper is to develop and demonstrate a fast and robust derivative-free workflow which improves economic values via optimizing water and gas flooding rate allocation by streamline-based technique.

Streamline-based rate allocation optimization has been demonstrated to be a powerful tool for application to waterflood operations. However, the utility of the technique has been limited in optimizing the Net-Present-Value (NPV) for improving the economics of these operations. In addition, the theoretical assumptions on physics limit its application to pressure-sensitive secondary or tertiary recovery processes such as gas injection. In the proposed workflow the expected NPV of each injector-producer pairs are evaluated at a given future business decision such as next infill time by using static, dynamic, and economic parameters such as price and discount rate along with time-of-flight. Then new flow rates are allocated based on the performance of the wells ranked by expected NPV to achieve better future economic value.

The proposed workflow was first compared with previous streamline-based rate reallocation technique using series synthetic models. Although all tested methods showed better performance when compared with the base scenario, our proposed approach showed improved performance in terms of NPV, primarily due to proper handling of the reservoir dynamics and economic value in the objective function. The workflow was then benchmarked by a case study of a field subjected to waterflood and gas injection. The results of proposed approach were comparable to the population based derivative-free techniques such as Genetic Algorithm (GA) or Particle Swarm Optimization (PSO) where many simulations are required to achieve a similar outcome.

The proposed workflow was coupled with next generation simulator and applied to various field studies. The method provides the ability to simultaneously control injector and producer flow rates for improving the economic value under multiple constraints. The workflow retains advantages of the conventional streamline-based technique such as fast post processing and ease of application to a broad field studies.
Identifying Cost-Effective Waterflooding Optimization Opportunities in Mature Reservoirs from Data Driven Analytics
Authors: Yrigoyen Andres , Saputelli Luigi , Chacon Alejandro , Chegin Jorge
Published: October 2017

Evaluating waterflooding process performance is one of the main concern prior to implementing such secondary recovery method. Big and complex numerical models are not the best tool for daily surveillance and monitoring. However, by applying analytical and data driven models to provide fast solutions and efficient diagnosis of waterflooding processes opens a new window to examine process advantages to improve injected water distribution and to provide recommendations for accelerated short-term production scenarios. By incorporating data driven techniques to perform history matching and forecast the reservoir management process gets improved because early action can be taken to minimize water production, well operational problems and cost reduction.

Data analytics techniques also help to reduce time-consuming data preparation and processing, and data uncertainty (i.e. geological, petrophysical, reservoir engineering). Effective reservoir management needs quick ways to predict injected fluid distribution to improve areal and vertical sweep efficiency during secondary and tertiary recovery processes. Consequently, simpler methods that provide fast results to substitute reservoir simulation (for surveillance and monitoring) are important for continuous reservoir management. In this work Capacitance Resistance Model (CRM), streamlines, and Normal Equation Algorithm (NEA) models were used as proven methods to address the above challenges. CRM and NEA model were used to perform history-matching and forecast based on production and injection scenarios to improve waterflood process oil recovery factor.

During this study, two scenarios were designed to test each model to investigate the advantages of (CRM) and NEA by incorporating different levels of data perturbation and to compare prediction accuracy. CRM and data driven models were able to reproduce historical data with low degree of error. CRM quickly compute allocation factor between injector and producer pairs. Allocation factor calculation allow the evaluation of waterflood performance by pattern while identifying the poor sweep efficiency areas. Better connectivity zones were easily identified by matching high allocation factor for the injector-producer pairs.

This work is an effort to demonstrates the value of predictive and prescriptive data analytics to effectively replicate production history, and generate solutions in a simple and fast approach, yet powerful to find optimal solutions in a short period of time. Using data driven models, a larger number of scenarios were run to optimize reservoir performance without performing expensive numerical simulation computations and to reduce engineering load to build, maintain and update models by around 80%.
Integrated Analysis of Reservoir Architecture and Quality for Effective Production: A Low Permeability Reservoir in Lower Jurassic Sandstones, West Siberian Basin
Authors: Gorbovskaia O. A. , Pishchuleva A. V. , Belozerov B. V.
Published: October 2017

The work deals with a conceptual geological model creation that is necessary for further geocellular modelling and field development scheme optimization. The object of the study is Lower Jurassic terrigenous formations U15 and U14 of Urman-Archin fields group located in south-eastern part of West Siberian basin. Low quality of these reservoirs requires detailed geological analysis for allocation of the most perspective zones. This work integrates the results of seismic, paleogeographic, palaeotectonic, logging, well testing, macroand microscopic core analyses. It was discovered that the formations were deposited in fluvial conditions. Moreover, the evolution of the river system is observed across the interval of U15-U14 formations – braided streams change to meandering ones. The sedimentary processes determine vertical and lateral lithological heterogeneities as well as the primary distribution of grains of different size characterizing the activity of depositional agent. However, it was found that lithology and grain size is not directly related to the presence of reservoirs, so sedimentary conditions are not the key factor of reservoir continuity. Analysis of diagenetic alternations of the formations’ rocks showed that their compaction influenced reservoir quality and its lateral heterogeneity. In some parts of the studied area the rocks are more compacted, and, consequently, they have lower porosity and permeability. Tectonic movements caused non-uniform rock compaction across the area. In addition, they led to reservoir compartmentalization. There are hydrodynamically isolated blocks, which may influence fluid distribution within the formations and should be considered during development scheme planning. Significant influence of diagenetic alternations on the reservoir properties is not typical for the deposits in terrigenous rocks within West Siberian basin, so this conclusion should be taken into account when analyzing similar reservoirs in this region.
A Game of Horizontals: The Dance of Gas Intrusion, Percolation, and Migration vs Mud-Weight Increase.
Authors: Stone Rick , Nauduri Sagar , Medley George
Published: October 2017

Gas intrusion, gas percolation, and bottoms-up gas are very common challenges when drilling and completing deviated, directional, and horizontal wells. Improper assessment and lack of mitigation plans can greatly increase associated risks, resulting in HSE problems and potential catastrophic events.

Several factors impact the manifestation of so-called "gas intrusion," such as the type of formations encountered while drilling and the method of drilling selected by the operator. After a great deal of research, several solutions were developed and became commonplace throughout the industry.

One of the key (yet debatable) techniques has been to increase the drilling mud-weight. This method was developed successfully for controlling gas intrusion during conventional drilling of vertical wells. In some cases, it can have quite the opposite effect, especially in deviated, directional, or horizontal wells. This is primarily because of the differences in the way fluids in horizontal wells interact under the influence of gravity (when compared with vertical wells). Even in this day and age, operators and company men sometimes inadvertently play a "dance" of gas intrusion and migration vs. mud-weight increase, a game of horizontals orchestrated by Mother Nature.
A Multifunctional Coated Proppant: A Review of Over 30 Field Trials in Low Permeability Formations
Authors: Radwan Amr
Published: October 2017

This paper presents a tailored coated proppant that provides improved solutions for various hydraulic fracturing challenges. The coating aims to enhance proppant transport with slickwater fluids while improving the hydrocarbon mobility into the proppant pack and reducing respirable crystalline silica during the operations. The paper discusses results from over 30 field trials in multiple low permeability formations.

The novel multifaceted coating was designed to modify the wettability of proppants’ surfaces to increase the surface's affinity for gases and reduce the generation of respirable airborne particles. By adding small volumes of gases into the proppant-laden slurry, gas bubbles get attached to the surface of the proppant leading to significant reduction in its apparent specific gravity. In order to prove the operational and economic advantages of the multifunctional proppant, a series of novel laboratory experiments were conducted under various operational conditions, followed by numerous field trials in several low permeability formations.

The laboratory tests showed that the coated proppant can stay suspended in the presence of gases for extended period of time. The laboratory evaluation involved testing under pressures and temperatures up to 12,500 psi and 400°F with different fluid systems made from both fresh and high-salinity waters. Oil mobility tests showed that the oil flow rate was increased by 74% compared to uncoated sand. Several multistage fracturing treatments executed with significantly higher proppant concentrations up to 6.1 lbs/gal in typical slickwater treatments when used with 1.5 – 10 % foam quality. Onsite measurements have proven that the coating reduced the generation of respirable airborne particles down to 10 – 30 μg/m3 throughout the proppant lifecycle. Data obtained from numerous field trials showed that the novel proppant technology resulted in improved well productivity, increased oil cuts and reduced water production.
Analyzing Gas Well Production Data through the Application of the Connected Reservoir Storage Model
Authors: Childers D. , Wu X.
Published: October 2017

This work presents a novel approach through the use of the connected reservoir storage model to accurately predict production performance of gas reservoirs, which have a complex reservoir geometry and have a large uncertainty of reservoir energy support. Based on the deconvolution of measured pressures and rate data from a well, a gas reservoir performance will be modeled using a group of normalized quantities with which the wells behavior can be accurately predicted in all flow regimes. No foreknowledge of reservoir geometries, petro-physical properties or fluid properties are required in the development of this analysis.

Reservoir storage is a time function defined as the product of the total compressibility and the reservoir volume at a particular time. Unlike with classical or curve fitting decline curve analysis, the connected reservoir storage model is based on the pressure diffusivity theory by the normalized production rate and normalized cumulative production volume through deconvolution methods. With the knowledge of reservoir volumes, the long term well performance of gas reservoirs can be predicted.

Through the development of the connected reservoir storage model, three profiles can be ascertained, and are interrelated, to shed valuable insight into the production potential, and health, of an unconventional gas reservoir. The three curves are the pressure drop curve, normalized curve and connected reservoir storage curve. Utilizing the three curves stated above embodies a more powerful reservoir performance analysis technique for predicting the production potential of complex reservoirs.

The connected reservoir storage model will be presented from the fundamental material balance approach and mathematical equations will be derived for this model as it relates to gas reservoirs. This concept will then be validated through the development of synthetic models with varying permeabilities, porosities and well geometries through the use of a reservoir simulation suite with known reservoir parameters along with the utilization of deconvolution techniques. Limitations involved with this method will be highlighted in the development procedures.

The connected reservoir storage model allows for the bridging of the production decline and reservoir pressure response from production data found in the public domain. This concept allows one to evaluate and forecast current and future volume production, reservoir pressure behavior, average reservoir pressure and determine original fluids in place with no prior knowledge of reservoir geometries, petro-physical data or fluid properties. With the development of this model decline curve analysis (DCA) can be extended into the transient regime of the production period.
Deep Learning for Steam Job Candidate Selection
Authors: Cheung Chung Ming , Goyal Palash , Tehrani Arash Saber , Prasanna Viktor K.
Published: October 2017

Choosing the most profitable wells for steam jobs is of high value given the cost and resources required for the procedure. To find the best candidates, we develop a system with two parts: i) An autoencoder to reduce the dimensionality of input data, ii) A kernel regression to predict the production gain. We show the benefit of application of autoencoder-extracted features by comparing the resulting accuracy with manually extracted features. To train our system, we use a training data set consisting of 3200 steam jobs and evaluate it on a testing data consisting of 800 steam jobs. We use various metrics, e.g., mean squared error (MSE), Spearman correlation and overlap coefficient, to evaluate the performance of the proposed system. We show that our system improves upon the existing methods significantly. For example, it can choose 50 steam job candidate wells out of 800 such that 98% of them are in the top 100 wells. The system also outperforms the wells chosen by engineers working in oilfield. We achieved an average percentage gain in production of 176% compared to 124% achieved by engineers.
Improving Malaria Prevention with Innovative Biotechnology Integration
Authors: Ngunjiri S. , Brown A. , Isnard A. , Taudon N. , Imbert C. , Fusai T. , Leclipteux T. , Lefevre O. , Lichtenberger J. M. , Deffaud C. , Diara M.
Published: October 2017

OBJECTIVES/SCOPE

The development of an immunochromatographic test for quick detection of malaria preventive medicines (doxycycline, proguanil and mefloquine) in urine is described. The test integration and observed results in ExxonMobil (EM) workplace malaria program are also presented for potential adoption by organizations seeking to improve adherence to malaria prevention in workers operating in endemic locations.

METHODS PROCEDURES, PROCESS

In 2007, EM established a unique partnership with the French Army Biomedical Institute and two biomedical engineering manufacturers to develop a rapid detection test (RDT). Using specific drug antibodies, they created the tests detecting doxycycline, proguanil and mefloquine in urine. After the initial proof of concept in the laboratory setting, the RDTs were tested in malaria endemic locations using urine samples from workers on malaria preventive medicines and laboratory methods were used to confirm the results. Following such validation process and commercial production, the tests were integrated into ExxonMobil’s malaria program with implementation completed in all eligible sites located in endemic areas by 2013.

RESULTS, OBSERVATIONS, CONCLUSIONS

The first tests successfully developed were for proguanil and mefloquine, followed two years later by doxycycline. The RDT validity was tested against the standard laboratory techniques which use High-Performance Liquid Chromatography (HPLC).

Using urine samples collected in Chad and Equatorial Guinea, 100% of the tests detecting the drugs were confirmed by the laboratory method. Reading and reporting issues were identified for the validation of proguanil and mefloquine and subsequently addressed by an improved test user guide.

For doxycycline EM phase, two different RDTs were compared on 99 urine samples and verified with HPLC: 86.9% tested positive by both RDT’s and 91.9% by HPLC. This could be attributed to the detection level set for the RDT. Only 8 samples were truly negative. A further comparison of the strips showed that one had well-marked responses and more stable immunoglobulins for the test component.

As a result of the test development and implementation, 65% of the 32,496 malaria drug prevention compliance tests performed between 2013 and 2016 were conducted by RDTs. They helped further reduce noncompliance rates, keep the number of cases as low as 15 per year and save approximately 1.6 million dollars during that period. Additional benefits are related to having immediate results and opportunity for timely counseling on malaria prevention.

The use of this newly developed rapid test detecting malaria prevention medicines in urine is an additional incentive for malaria chemoprophylaxis compliance. It is affordable, practical and commercially available to help reduce malaria risk and consequences to companies and their non-immune workers going to malaria-endemic locations.
Unique Design and Performance of a High Temperature Viscoelastic Diverter Pill for Sandstone Acid Yields Better Diversion Response and Increased Production
Authors: Usie Marty , Carman Paul , Langlinais Kevin , Nino-Penaloza Andrea , Mccartney Elizabeth
Published: October 2017

Foam diversion has industry recognition as a proven approach to diversion in remedial sandstone acidizing in deep-water environments. With long intervals and large displacement volumes it is critical that a stable diverter reach the perforations with sufficient viscosity to sustain diversion effectiveness. Industry publications and laboratory testing indicate that non-stabilized foam systems tend to breakdown over time. A novel sandstone acidizing diverter (SSAD) system was recently developed and applied successfully in the field.

The new SSAD system is comprised of a surfactant based gelling agent prepared in an ammonium chloride base fluid. The formulation of the SSAD system can be altered as needed to obtain desired rheology and break profile. In order to demonstrate the viscosity potential of this system, formulations without breaker were prepared in the laboratory for each specific well application at bottom-hole temperature. For instance, a formulation designed for 240 °F bottom-hole temperature, provided a stable viscosity slug of 300 cp at 100s-1 for six hour duration. The system maintained viscosity above 100 cp at 40s-1 after six hours with internal breaker.

In 2015, two wells in deep water Gulf of Mexico with 200°F bottom-hole temperatures and an average perforated interval of 114 ft were treated with an organic mud acid treatment with no diverter. These zones were then re-stimulated in late 2016 with the same organic mud acid system and the new SSAD system. The initial production of the two wells treated in 2015 versus the re-stimulation treatment in 2016 showed a twofold production increase. Diversion pressure response was observed to be as high as 285 psi.

The SSAD system can be applied in wells with low and elevated bottomhole temperatures up to 300°F. The SSAD system is non-damaging to the formation and will break in presence of hydrocarbons, or an internal breaker can be added for enhanced clean-up. Other features include extended fluid stability and no additional mixing equipment or personnel requirements compared to foam.

The case study of the two wells in deep water Gulf of Mexico demonstrates the effectiveness of the new SSAD treatment compared to the conventional treatments without diversion being previously pumped in the Gulf of Mexico. Not only do SSAD treatments provide enhanced diversion compared to foam, on average, the cost of an SSAD system is 25% less than a treatment using foam diversion.