bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Approach to Operational Excellence for Oil and Gas
Authors: Buzzo Marco , Mazzoni Marco
Published: March 2019

Organizations generally run several improvement initiatives simultaneously targeting different aspects of their operations. These initiatives will improve the specific operation efficiency, but due to the fragmented approach don't necessarily lead the organization to lasting results. The overall effectiveness can be improved by an all-embracing program allowing all initiatives to align, leverage one another and succeed – approach commonly identified as Operational Excellence (OE) [1]. Even if a standard definition of OE is not specified, its concept has been developed around 2000 in the Quality circles [2] and rapidly spread as an evolution of the total quality management [3]. OE - due to its amplitude, requires a long-term sustained commitment from executives, senior leaders and employees. In the past this approach would have made little sense for most operations in the Oil and Gas industry due to their predictability and stability. In the last decade this industry has been under a continuous pressure due to a constant decline in the oil barrel price coupled with rising exploration, development and production costs, putting margins under significant pressure. Furthermore, the market push for risk reduction even when the industry is taking new challenges like drilling in ultra-deep-water or in the Arctic, intensive onshore operations in populated areas (like shale gas in the northeastern US) and pioneering technologies like floating liquefied natural gas terminals. Industry executives are working to define and deliver OE at such frontiers, where few benchmarks exist.

The need of enterprise-wide operational effectiveness and to achieve consistently better results in the Oil and Gas industry has been also seen as market evolution from the top consulting firms that offer such dedicated services. It has been estimated that a 10% production capacity is locked up in complexity and inefficiency—a valuable opportunity for improvement [4]. Despite these opportunities, OE implementation literature in Oil and Gas is marginal and experiences have been mainly reported limited to the field of health, safety and environment [5], [6], [7].

This work presents a novel approach to OE in the Oil and Gas industry, carried out at Backer Hughes, a GE Company in its Turbomachinery & Process Solutions division. This part of the organization represents a common complex case study in this industry, due its global footprint where a constellation of more than 100 manufacturing, engineering and service sites hosting more than 12000 employees. The next chapters present the assessment, selection and adoption of a standard OE model, the evaluation of current operations with respect to the model and the development of initiatives supporting it.
High-Pressure, High-Flow-Rate Stimulation Equipment for Shale Fracture Treatments
Authors: Surjaatmadja Jim B. , Logan Tom , Hunter Timothy H. , Stephenson Stanley V. , Bull Brad , Lucas Bryan
Published: March 2019

The success of the Americas with stimulating shale formations has drawn attention to unconventional implementations globally. While excellent production results and economic successes are well publicized, equipment performance is one of the major factors responsible for economically delivering effective as-designed stimulation treatments. Delivery efficiency is the top priority of well servicing equipment design and maintenance personnel.

Equipment redesign is occurring industry-wide, and new system offerings promise greater operational efficiencies—some have already demonstrated success and others are still being developed to identify or provide improved efficiency solutions. To accomplish this, each piece of equipment, whether a pump, a blender, a container, or even a measuring/monitoring device, is carefully evaluated. Their collaborative task is to deliver treatment material and energy from some known surface point to a specific point or zone of a wellbore within the geological formation. Every subsystem is evaluated so that each subtask is performed effectively at a reduced time and cost.

Shale development affects decisions on how to develop a geological formation for maximized economic return. Multiwell pads, increased well density, and fracture requirements are pushing equipment to their limits, including requiring pumping equipment to continuously deliver high pressure fluid with little idle time for maintenance and repair or replacement (blending equipment has similar limits). Material delivery from source to location is important; this is particularly true for proppants because a continuous supply of 3,000 to 15,000 lbm/min is typically necessary. Finally, while well spacing is being drastically reduced, the ability to treat many wells in quick succession has become necessary.

This paper discusses steps taken to improve high horsepower treatment issues, reduce nonproductive time, and achieve efficiency targets.
The Application of Downhole Seismic Imaging in Identifying Natural Fracture Systems; An Integrated Approach Utilizing Core and Borehole Image Data
Authors: Amer AimenAi , Sajer Abdulazziz , Al-Adwani Talal , Salem Hanan , Abu-Taleb Reyad , Abu-Guneej Ali , Yateem Ali , Chilumuri Vishnu , Goyal Palkesh , Devkar Sambhaji
Published: March 2019

Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes.

Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network.

This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production.

The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors.

Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.
Multi Stage - Open Hole Completions: Continuous Successes in Placing Multiple Fractures in a Single Tight Gas Sandstone
Authors: Arevalo Alfredo , Buenrostro Adrian , Espinosa Mauricio , Harbi Abdulaziz
Published: March 2019

Tight sandstone reservoirs under this project have been a challenge to stimulate due the high breakdown pressure required to create the fracture, and a challenge on production recovery due fast decline observed in some of these wells. Exploring Multi Stage Fracturing completion in horizontal wells in these tight sandstone reservoirs increases the overall reservoir exposure to stimulation treatments by Hydraulic Fracturing, and expects a better and longer production performance. This paper evaluates the recently deployed Open Hole – Multi Stage Fracturing completions (OH-MSF) over tight sandstone gas reservoirs.
KSI Field Fast Track to FID
Authors: A. Al-Hashemi A. , Jabri Gharbi , Khudhuri S. , Marjibi I. Tobi , Hamed Tope
Published: March 2019

This paper discusses KSI project which is the first in-house study on QA Cluster, aimed to accelerate delivery. This abstract spotlights the surface & subsurface integrated work results on fast track from DG1 to FID within 1.5 years by utilizing data from analogue fields & replication of surface concept & facility design.

For the subsurface, an extensive analogue study was conducted. Then simple 1D analytical model used to generate well by well forecast. A small box model constructed to test different water flood development sensitivity & define the optimum spacing, type of pattern & water injection depth where the outcome compared with 3D simulation model & they match.

For the surface, a small Well Test Unit (WTU) is leased to maximize the oil production from KSI field & provide an early view of reservoir waterflood uncertainty. The full field surface facility concept is a replication from H analogue field. This replication leads to accelerate the on stream date by 24 months.

KSI is a green field which is one of the Lower Shuaiba pancake reservoir where it transferred from exploration with a high UTC project & very long schedule.

It was identified that the key critical success factors are accelerating initial oil production & reducing Capex by using analogue field data, optimized phased-development, replication for facility design, & optimized well design & well spacing.

Comparing the KSI field with analogue fields, resulted on chosen a line-derive waterflood as development concept which was validated by running a box model.

The good match achieved between 1D analytical model used at DG2 & 3D simulation model used at DG3 indicated that the analytical model is sufficient as promise for Field

Development Plan (FDP). However the numerical model will be needed for easily future waterflood management.

Changing the well completion design from single horizontal to dual lateral is resulted in reducing the CAPEX (Drillex) by 54%. The replication of surface facility resulted on achieving two years ahead of initial schedule.

The in-house study & replication of surface facility led to reduce the total project CAPEX 7%, increase NPV by 77%, reduce the project UTC by 21% & accelerated the schedule by 2 years as below figure 1
Hydraulic Fracturing Treatments in the Permian Basin: Distillation of Best Practices in the Spraberry and Wolfcamp Formations
Authors: Othman Amro Abdelrahman , Amao Abiodun Matthew
Published: March 2019

Hydraulic fracturing is being used globally to unlock hydrocarbon resources in unconventional reservoirs. However, the efficient utilization of resources in most treatment designs is debatable. A study of hydraulic fracturing treatments in 56 vertical and horizontal wells representing 1,151 treated stages in the Wolfcamp and Spraberry formations of the Permian Basin in West Texas was conducted in this paper. Intrinsic treatment strategies and operational methodologies used by the well operators were evaluated with the objective of extracting and deducing insights into criteria that characterize operational virtuosity, efficiency and inefficiency.

Treatments of vertical wells were studied with 25 wells in both formations, in the Midland basin. 18 wells were studied in Spraberry horizontal well treatments, while horizontal Wolfcamp treatments were studied with 13 wells in the Delaware basin. Well completion records, treatment reports and well files were reviewed for treatment parameters on each well. The study concentrated on indices like, proppants types and amount; fluid types and volumes pumped; treatment rates and pressures; productivity and treatment cost. Empirical and statistical analysis using correlations and analysis of variance were then conducted and used to identify the best practices that actively and positively increased production rates and decreased production costs in each of these formations and well types.

The Spraberry is very fine-grained sandstone, siltstone and carbonates with interbedded shales in the studied area. The Delaware Wolfcamp is a complex formation with carbonates, mostly limestone, and interbedded organic rich mudstones in varying proportions. Results show that the use of 20/40 white as a proppant is not economical, in both formations either in vertical or horizontal wells, because of the huge increase in treatment costs. Use of 100 mesh and 40/70 white proppant in both formations was amenable to better production rate. Results show that usage of crosslinked gel increases treatment costs drastically. Slickwater was found to improve production rates, although huge volumes were needed for large proppant amounts. The use of HCl acid as spearhead in formations with high carbonate content like the Wolfcamp was found to improve treatment results. Increasing the number of stages increases treatment cost, but increasing the perforated intervals correlates positively with production rate.
Performance Analysis of Acid Fracturing Treatments in a Sour Gas Carbonate Reservoir
Authors: Eze Samuel Okorie , Ayoola Olakunle T. , Hussain Baleegh A. , Khaldi Humoud H.
Published: March 2019

This paper presents a new insight into the factors that affect the initial productivity of Acid Fracturing (AF) treatments in a sour gas carbonate reservoir.

Acid Fracturing is a stimulation technique used to improve the productivity or injectivity of wells. It involves pumping acid into a formation at above fracture pressure, and can treat deep into the formation. Despite the benefits of acid fracturing, conditions are not always favourable for acid fracturing. This could be due to reservoir or well limitations for example, very low formation permeability, formation temperature especially in dolomite formations, and/or well completion integrity.

In this application, a total of 12 wells were stimulated after initial completion by acid fracturing. The treatment design is a single stage Pad-Acid treatment which involves pumping 1) pre-acid, 2) gelled water, 3) main acid, 4) diverter, 5) repeat of steps 2 to 4 as required, then followed by 6) a post-acid flush and 7) over-flush. Optimisations made on the treatment design as the campaign progressed include use of specially formulated diversion system, ramp up of acid injection rates and volumes.

The analysis of pre and post stimulation productivity performance show the following: An average productivity improvement of 9 times the pre stimulation productivity,A direct relationship between productivity improvement and increasing the rates/volumes of acid injection during the treatment,That treatment volume did not always result to productivity increase but the manner and sequence of fluid injection were of greater effect on productivity.Fluid diversion system blended with particulates show greater increase in productivity than wells treated with diversion systems with no particulates.

Based on the results, it can be concluded that, an optimized method of ramping up acid injection rate/volume as well as careful selection of diversion system can lead to productivity improvement of up to 9 times the pretreatment productivity in Carbonate reservoir stimulation.
Recognizing Abnormal Shock Signatures During Drilling with Help of Machine Learning
Authors: Ignova Maja , Matheus Justo , Amaya Darwin , Richards Edward
Published: March 2019

Drilling generated shocks and vibrations (torsional, axial, and lateral) are among the main causes of failures in the drilling industry; because they affect the rate of penetration, directional control, and wellbore quality. Rotary steerable system tools are equipped with measurement devices such as magnetometers, accelerometers, and shocks and vibration sensors from which statistical information is obtained, such as root-mean squared error, maximum peaks, and peak levels. From these statistics, whirl, bit bounce, and stick/slip severity are inferred. Often, the derived statistics are not enough to distinguish between normal drilling versus abnormal drilling for a location in the wellbore or to determine whether the shocks and vibrations are the result of poor drilling practice, formation disturbances, or mechanical failures of the bottomhole assembly, including the bit.

Machine learning methods were used for analyzing the high-frequency radial shock burst data, which compresses and classifies the data; i.e., good drilling and abnormal drilling. The method is capable of further clustering the data into whirl or no whirl, bit-bounce or no bit-bounce, formation change or no change, and/or faulty equipment and parts; thus, assist in the robust post-failure analysis of existing data sets and prevent catastrophic failures in real time and improve the trajectory control.
Rock Mechanical Characterization of Unconventional Source Rocks
Authors: Lee Ji Soo , Jacobi David , Alnajar Zainab
Published: March 2019

Rock strength is an important property to measure for determining its effect on drilling, wellbore stability, and potential well completions associated with hydraulic fracturing of unconventional reservoirs. The industry traditionally relies on elastic moduli measured from core plugs to determine the stress anisotropy to predict the extent of hydraulic fractures. This provides some estimate of the expected stimulated rock volume in unconventional reservoirs. Rock strength however based on the finding of this study could also be a factor that needs to be considered for designing hydraulic fracturing plans to stimulate production from the rock volume. However, rock strength is difficult to measure in highly laminated source rocks comprising unconventional reservoirs. The existence of weak, horizontal bedding planes within the laminated rock fabric creates anisotropy that influences the rock strength values obtained. Moreover, drilling and extracting intact horizontal, vertical, and diagonal core plugs to test the effects of anisotropy on the rock strength is difficult to achieve. Often, the plugs fracture during extraction due to the laminated fabric. To compensate for the challenge of extracting intact core plugs from these lithofacies, this study proposes that rock strength can be estimated without the need of extracting core plugs. Instead, a new method is demonstrated where non-destructive rebound hardness measurements are collected across a specifically gridded, slabbed rock surface to provide an estimate of the rock strength. The collected rebound hardness values are converted into unconfined compressive strength values using an empirical algorithm. The empirical algorithm was developed using unconfined compressive strength values measured from core plugs correlated to rebound hardness numbers measured from the face of those same core plugs. The derived unconfined compressive strength values are then used to represent the source rock's mechanical characteristics which can be presented as a contour map across the surface. These results have been correlated to the mineralogy of the rock surface, quantified and mapped using micro-X-ray Fluorescence elemental maps. Differences in unconfined compressive rock strength can then be correlated to the changing mineral content of the rock surface. This non-destructive estimation of rock strength was conducted to address the challenge of relating core scale measurments to reservoir scaled analysis to improve hydraulic fracturing designs in unconventional source rocks.
Real-Time High Data Rate Bidirectional Fiber-Optic Telemetry for Harsh Environments
Authors: Stark Daniel , Schaecher William , Maida John , Wiecek Bogdan
Published: March 2019

Data telemetered in harsh environments are traditionally compressed, filtered, and processed before being transmitted, if telemetered at all. The user then has limited information about the status of monitored systems; however, the user's knowledge can be improved by real-time raw information transmission.

In harsh environments, data are traditionally transmitted over dedicated lines, through variations in a power source, or wirelessly. These methods suffer from signal attenuation and dispersion over long lengths, leading to lower data rates. Optical fiber systems, however, have low attenuation, little dispersion, and can use a variety of communication schemes, such as varying signal amplitudes, phases, or wavelengths. In particular, quadrature amplitude modulation (QAM) or pulse amplitude modulation (PAM) methods common for fiber telemetry backhauls can achieve greater bandwidths in harsh environments to realize real-time data retrieval without the need for processing.

This paper reviews the current state-of-the-art fiber-optic telemetry systems for harsh environments and discusses a proof-of-principle demonstration using higher-order optical modulation techniques to obtain data rates that are orders of magnitude greater than those achieved by electrical telemetry equivalent systems. The demonstration consisted of optical and electrical components that operated at temperatures up to 200°C and transmitted data along 18 km of fiber with over 10 dB of optical margin. The current state of the project and its application to a wide variety of possible field uses are explored.

Additionally, the use of fiber communications is reviewed to help improve data delivery to users in the energy industry, a topic of growing interest. It also highlights the innovative approaches for developing real-time, high-data-rate, bidirectional optical fiber telemetry for harsh environments.
Evolution of a Lab-Optimized ASP Formulation for a High Temperature and High Salinity World-Class Clastic Reservoir in the Middle East
Authors: Al-Murayri Mohammed T. , Kamal Dawood S. , Baroon Hadeel F. , Shahin Gordon T. , Shukla Shunahshep R.
Published: March 2019

This paper discusses the evolution of an Alkaline Surfactant Polymer (ASP) formulation for a challenging sandstone reservoir in North Kuwait. This is an on-shore reservoir, with no gas cap, featuring a moderately high residual oil saturation to waterflood of approximately 20-30%. Moreover, the reservoir has a light oil (API Gravity 30-35) with low Total Acid Number (TAN) and is undergoing a maturing waterflood – thus making it amenable to ASP implementation. However, the high reservoir temperature (90°C), in-situ brine salinity (>250,000 ppm) and divalent ion concentration (>20,000 ppm) place the reservoir at the upper threshold of ASP technology implementation.

In addition, the oil has a high emulsification tendency and was observed to form very stable brine-oil emulsions when sampled from the field. This was due to the high concentration of heavier components such as waxes, resins and asphaltenes, some of which are surface-active and tend to interfere with the action of synthetic surfactant at the oil-water interface making ASP formulation development for such oils very challenging. Furthermore, addition of polymer to improve the ASP/oil mobility ratio caused phase separation of the aqueous phase likely because the water-soluble polymer preferentially dissolves in brine while pushing out the hydrophobic surfactant. The methodology followed in this work was to select a surfactant with a high alkyl tail length to solubilize the heavier hydrocarbons in the oil, blend it with a more hydrophilic surfactant to increase the optimal salinity to match the target injection water salinity and overcome the surfactant phase separation issue when polymer was added to the formulation. The ASP formulation was successfully tested in the field in a Single Well Chemical Tracer Test (SWCTT) and was successful in reducing the remaining oil saturation from 0.24 ± 0.02 at the end of water flood to 0.06 ± 0.05 at the end of the chemical flood.
Analysis of Water/Oil Ratio in Complex Carbonate Reservoirs Under Water-Flood
Authors: AlOtaibi Shabab , Cinar Yildiray , AlShehri Dhafer
Published: March 2019

Knowing the source of excessive produced water from oil wells in complex carbonate reservoirs under water-flooding sheds light for engineers to optimize development plans and better design remedial actions for enhanced water management. Although oil-well water production has been studied extensively, and hence different techniques have been introduced, only a few have addressed the source of produced water. Chan (1995) was among first to develop diagnostic plots to analyze the water-oil ratio (WOR). Chan plots (double-logarithms of WOR & its time derivative WOR’ vs. time) can, for example, indicate whether produced water comes through water coning or water channeling. Yet, these plots were obtained from conceptualized black-oil simulations which should be validated by more diverse field data. In this paper, Chan diagnostic plots were scrutinized using a suite of diverse field data that include permeability, production logs (PLT) and pressure transient analysis (PTA) from many vertical and horizontal wells with different completions. In this study, we demonstrated that more benefit of using Chan plots to diagnose water source can be gained through incorporating other field data into the analysis such as core data, PLT, and PTA. The diverse examples presented in this study revealed that near-well reservoir characteristics play a major role in shaping WOR & WOR’ plots rather than the well being whether vertical or horizontal. We suggest that, for a more accurate Chan analysis, only the production data at constant total liquid rate should be used. The second derivative of WOR may be utilized to identify the concavity of the WOR curve or the slope of the WOR’ curve.
Sour Fluids Management Using Non-chemical H2S Scavenger
Authors: Dhulipala Prasad , Jani Jagrut , Wyatt Melanie , Leidensdorf Jeremy , Chakraborty Soma
Published: March 2019

The objective of this study was to develop and apply a non-chemical based environmentally preferable hydrogen sulfide scavenger that addresses secondary issues caused by current chemical scavengers like triazine and glyoxal and to confirm its ability to mitigate sulfide in different applications. Recombinant DNA and protein expression technologies were exploited to develop this novel H2S scavenger.

This non-chemical scavenger (NCS) is generated by cloning the cDNA sequence from a thermophilic organism and expression of the encoded protein in suitable vector. Non-chemical based formulation was developed and blended in a pilot plant. The efficacy of the scavenger was evaluated in sour brine, crude oil and mixed production fluids from different sources. Sulfide concentrations before and after reactions in headspace were measured by using Dräger gas detection tubes (ASTM D5705). Corrosion testing was performed using kettle tests. Field assessment of the scavenger was carried out by treating sour oil at the Bakken oil field as per the field testing plan.

In this study, H2S mitigation was addressed using a novel non-chemical scavenger generated from thermophilic bacteria from lab scale to pilot scale. Functional studies conducted by treatment of soured brine and oil revealed 72% and 90% reduction in H2S concentration respectively. The scavenger showed a 75% reduction of sulfide in simulated mixed production samples containing 30:70 ratio of brine and oil. Limited testing of this scavenger in field showed reduction of headspace sulfide from 400 ppm to 2 ppm. In addition, the field data showed less than 0.5% BS&W. The scavenger also showed no significant increase in corrosion during the scavenging reaction.

These studies confirm that this novel non-chemical scavenger can be successfully used to mitigate H2S in various systems without causing adverse effects that were seen with chemical scavengers. A non-chemical scavenger has several advantages such as meeting environmental regulations, reducing, or eliminating secondary effects like solids formation, corrosion, scaling, and health hazards that are associated with current chemical scavengers.
Assessment of Big Data Analytics Based Ensemble Estimator Module for the Real-Time Prediction of Reservoir Recovery Factor
Authors: Tewari Saurabh , Dwivedi U. D. , Shiblee Mohammed
Published: March 2019

Production of oil & gas depends upon the recoverable amount of hydrocarbon existing beneath the underlying reservoir. Reservoir recovery factor provides of the production potential of ‘proven reservoirs’ which helps the planning of field development and production. Estimation of reservoir recovery factor, with a good degree of accuracy, is still a challenging task for engineers due to the high level of uncertainty, large inexactness, noise, and high dimensionality associated with reservoir measurements. In this paper, we propose a big data-driven ‘ensemble estimator’ (E2) module, comprising of wavelet associated ensemble models for the estimation of reservoir recovery factor. All the ensemble models in E2 were trained on big reservoir data and tested with unknown reservoir data samples obtained from U.S.A. oil & gas fields. Bagging and Random forest ensembles have been utilized to correlate several reservoir properties with reservoir recovery factor. Further, E2 utilizes Relief algorithm to understand the significance of reservoir properties effecting the recovery factor of a reservoir. The proposed E2 module has provided impressive estimation results for the determination of reservoir recovery factor with minimum prediction error. Random forest has given the highest coefficient of correlation (R2=0.9592) and minimum estimation errors viz. mean absolute error (MAE=0.0234) and root mean square error (RMSE=0.0687). The performance of the proposed E2 module was also compared with conventional estimators viz. Radial basis function, Multilayer perceptron, Regression tree and Support vector regression. The experimental results have demonstrated the supremacy of E2 over conventional learners for the estimation of reservoir recovery factor.
Application of Automated Machine Learning for Multi-Variate Prediction of Well Production
Authors: Maucec Marko , Garni Saad
Published: March 2019

Performance evaluations of oil and gas assets are crucial for continuously improving operational efficiency in the mainstream petroleum industry. The success of such evaluations is largely driven by the analysis of the data accumulated during the asset's operational cycle. Usually, the amount of data stored in the databases dramatically exceeds the ability to approach the analysis with traditional spreadsheet-based tools or linear modeling. In this study we use data mining with multivariate predictive analytics and monetize on the value of data by transforming the inferred information into knowledge and further into rigorous business decisions.

With the expansion of the Digital Oil Field and transformation into the 4th Industrial Revolution, the oil and gas industry is acquiring tremendous amounts of data that come from disparate sources in a variety of origins, time scales, structures and quality. The underlying variable root-cause relationships are highly non-linear and non-intuitive, and simplistic linear regression methods are suboptimal. We approach the challenge by developing a data-driven workflow that integrates components of artificial intelligence, machine learning and pattern recognition to enhance quantitative understanding of complex data.

The sanitized aggregated data set combines 470 horizontal wells, covering 15 numerical (e.g., stimulation interval length, production rates) and categorical (e.g., target zone, proppant type) predictors and the total produced BOE, as the response variable. The objective is to predict an optimal set of variables that maximize the production. We utilize an integrated analytics platform that enables a variety of sophisticated statistical operations on large-scale data: a) comprehensive data QA/QC for outliers, consistency and missing entries; b) Exploratory Data Analysis and visualization; c) feature selection, screening and ranking; d) building and training of multiple machine learning (ML) models for multi-variate regression (e.g. generalized linear model, deep learning, decision tree, random forest and gradient boosted machine); and e) response optimization of an identified "best-performing" ML model for highest prediction accuracy.

Our study introduces the initiative to establish concepts best practices for predictive and prescriptive analytics in domains of reservoir simulation, description and asset management. Given the unique volume and information richness of operational data, acquired over decades of production history, the anticipated applications of predictive analytics could expand to drilling optimization, smart data aggregation, well stimulation and equipment maintenance.
Enhancing the Near-Surface Image Using Duplex-Wave Reverse Time Migration
Authors: Sindi Ghada , Alkhalifah Tariq , Fei Tong , Luo Yi
Published: March 2019

Reverse time migration (RTM) involves zero-lag cross-correlation of forward extrapolated source function wavefields and backward extrapolated receiver wavefields. For a near surface with complex structures and velocity anomalies, forward propagating the source wavelet generates wavefields containing reflections, near-surface multiples, and scattered direct arrivals. The wavefields are recorded as upgoing arrivals contaminated by the same reflections, near-surface multiples, and scattered signals, which can be critical for imaging near-surface structures and scatterers.

Here, we develop a new depth migration, duplex reverse time migration (DRTM) technique to improve imaging of complex near-surface structures. DRTM uses the direct arrival as a source to forward propagate and generate source wavefields, and reversely extrapolated recorded data in a zero-lag cross-correlation imaging condition to generate the final section. The interaction between the data components during cross- correlation can use primaries and multiples to image the near-surface structure correctly. Cross-talk artifacts may exist, but they are comparatively weak.

DRTM is demonstrated on both synthetic and field data examples showing an enhanced image in areas with complex near-surface structures compared to conventional RTM imaging methods. The new algorithm can significantly enhance shallow imaging without additional computation costs compared with conventional RTM. It can produce an image with higher resolution and signal-to-noise (S/N) ratio by replacing the source wavelet with the recorded direct arrivals, which include near-surface information necessary to boost the image in areas with near-surface complexity. Since the direct arrivals are one of the most energetic events recorded, the resultant image is typically of high S/N. The wave can also illuminate shallow zones better than primaries in marine environments.
Evaluation of the Performance of a New Biodegradable AA-LDHI in Cyclopentane Hydrate and CH4/C3H8 Gas Hydrate Systems
Authors: Henry Delroisse , Gilles Barreto , Jean-Philippe Torré , Christophe Dicharry , Philippe Glénat
Published: March 2019

The main objective of this work is to evaluate the performance of a readily biodegradable anti- agglomerant, called AA-LDHI, not harmful for the environment following the European legislation. It was tested in cyclopentane (CP) hydrate and methane (CH4)/propane (C3H8) hydrate systems. The performance of AA-LDHI was first tested in a batch reactor by torque measurements with the two hydrate systems in oil-dominated conditions (70 vol%). The experiments were performed for a subcooling of 6 °C for the CP-hydrate and up to 17 °C for the gas hydrate. The impact of AA-LDHI on hydrate growth pattern and on hydrate crystal morphology were investigated by microscopic observations at the water/CP interface for the CP-hydrate system, and at a water/(n-octane + CH4/C3H8) interface for the gas hydrate system. Then, AA-LDHI was evaluated in a semi-industrial flow loop.

Without surfactant, the hydrate formed a polycrystalline shell at the water/oil interface. With AA- LDHI, large conical hydrate crystals with the vertex pointing to the aqueous phase grew at the interface before sinking in the aqueous phase. The results obtained with both CP and gas hydrates are consistent amongst themselves.

In the batch reactor experiments without surfactant, hydrate crystallization led to a significant increase in the torque value and finally to the blockage of the agitator. With AA-LDHI, the torque remained almost constant at the baseline showing that this AA presented good anti-agglomeration performance. The microscopic observation in a CP phase of CP-hydrate particles formed in the reactor showed large water-wettable particles (about 400 μm) gathered in clusters but not agglomerated.

AA performance of AA-LDHI was also evaluated in a semi-industrial flow loop (1-inch diameter & 35.6 m total length) in similar conditions with CH4/C3H8 mix gas but using real condensate. This experiment proved that the AA-LHDI is fully efficient in transporting safely hydrates.
Optimization of Hydraulic Fracture Spacing Through the Investigation of Stress Shadowing and Reservoir Lateral Heterogeneity
Authors: Alrashed Ahmed , Miskimins Jennifer , Tura Ali
Published: March 2019

Monitoring of multi-stage hydraulic fractures in unconventional reservoirs has shown that some fractures are more effective and productive than others. Stress shadowing, in addition to reservoir lateral heterogeneity, are two potential factors behind this phenomenon. The focus of this study is to find the optimum hydraulic fracture spacing that aims to reduce the stress shadowing effect and ensure placement of hydraulic fractures in the best quality reservoir rock along the horizontal lateral.

A base hydraulic fracture model was created for a well in the Eagle Ford reservoir. Fiber optic distributed acoustic sensing (DAS) data were analyzed to find the individual perforation cluster contribution to production based on the total proppant placed in each cluster. The modeled well cluster contribution and production data were then matched with actual data. Reservoir and geomechanical properties for certain stages of the horizontal wellbore were altered from the base model to address the effect of rock quality lateral variations. Four scenarios of 57 ft, 76 ft, 100 ft, and 142 ft spacing between perforation clusters were investigated to address the effect of stress shadowing.

The sensitized reservoir and geomechanical properties include matrix permeability, Poisson's ratio, and Biot's coefficient. Increasing the matrix permeability from a base value of 0.2 ?D to 2 ?D caused the flowing fracture lengths to increase by 69%, 68%, and 48% in the heel, middle, and toe clusters, respectively. Stages with higher Poisson's ratio of 0.33, compared to a base value of 0.28, created larger flowing fracture lengths by 32% and 41% in the heel and middle clusters. Altering Biot's coefficient resulted in the same effect on flowing fracture lengths as altering Poisson's ratio. Overall, the rate of increase in flowing fracture lengths as a response to changing these properties was found to be more pronounced in the heel and middle clusters but less evident in the toe clusters. As for the cluster spacing scenarios, simulations showed that tighter spacing scenarios yielded a larger fracture network volume due to the higher number of clusters. However, these created fractures were less conductive than the ones created with wider spacing scenarios due to the stress shadowing effects. Production runs showed that scenarios with more accessed reservoir volume via more perforation clusters yielded a larger cumulative production over a 30-year simulation period.
A New Approach to Simulate Low Salinity Water Flooding in Carbonate Reservoir
Authors: Aljaberi Abdulla , Sohrabi Mehran
Published: March 2019

Low salinity water flooding (LSWF) as an enhanced oil recovery method (EOR) has attracted increased attention from oil companies due to its numerous benefits and advantages. It has been confirmed in several studies and laboratory experiments that LSWF has improved oil recovery. However, the underlying mechanism responsible for such an impact is still debatable. All previous studies focused on a geochemical process where fluid-fluid interaction has been overlooked. Recently, some studies have indicated that brine-crude oil (micro-dispersion) interactions play dominant roles in improved oil recovery in carbonate rocks. Nevertheless, at the moment, no commercial simulator can mimic this mechanism from the perspective of fluid interactions. In this work, we investigated whether micro-dispersion is applicable in commercial reservoir simulators through the history matching of two carbonate coreflood experiments. In this part of the investigation, three aspects will be addressed. (i) Develop a correlation of the link between the mechanism (micro-dispersion) in the lab and numerical simulation. (ii) Predict the low salinity relative permeability curves. (iii) History match the experimental data. This paper presents an integrated method of simulating low salinity water floods in carbonate rocks.

Two different approaches have been applied to the history matching of unsteady state coreflood experiments. First, numerical simulation was performed to extract the high salinity relative permeability curves (KrHS) of the secondary mode for both experiments. Then, the findings from the first approach and the experimental results were used to develop a new approach for predicting the low salinity relative permeability (KrLS) curves. The new approach was not only used to predict KrLs curves through micro-dispersion but also used as input to history match the tertiary low salinity water floods. An excellent match was obtained using both the numerical simulation model and the new approach for the oil recovery and pressure drop profile, where two different relative permeability sets were generated in this study for each coreflood. The first observation promotes the premise that a history match of a coreflood can be obtained using different sets of relative permeability curves. In contrast, the Corey exponents, residual oil saturations and endpoints are essential parameters in the history matching of LSWF. The results obtained in this study will help to understand the modelling process involved during oil recovery by LSWF and introduce a new approach to model the effect of LSWF.
Characterization of Native Colloids and Study of Emulsions Stabilized by Asphaltene, Wax, Silicates and Calcites Using Optical Analyzer Turbiscan
Authors: Abubakar Umar Abubakar , Mohd Saaid Ismail , Adebayo Sulaimon Aliyu , Mohd Pilus Rashidah , Amer Nurul Asna , Halilu Ahmed , Mamo Negash Berihun
Published: March 2019

Water-in-oil petroleum emulsions were prepared using response surface methodology (RSM) based on box-Behnken design (BBD). The emulsions were prepared using a treated Malaysian offshore crude oil, where the saturates, aromatics, resins and asphaltenes (SARA) of the crude oil were extracted using a modified SARA analysis. Other native solids, wax and asphaltenes extracted from oilfield emulsions and other crude oils were used as the emulsifying agents. In this paper, we focus on the characterization of some oilfield solids extracted from Malaysian offshore fields and further investigated their potentials to stabilize petroleum emulsions. The effects of the solids alone, and in combination with asphaltene/resin and wax were studied using statistical methods and the stabilities of the emulsions examined using a Turbiscan optical analyzer. The main advantage of Turbiscan is to obtain a faster and more accurate detection of destabilization phenomena in non-diluted emulsion than can be detected by the naked-eye (observation), especially for an opaque and concentrated dispersion system. The sample characterizations were conducted with FTIR, TGA, FESEM/EDX, XRF and XRD. Results showed that the major native solids present in the samples were paraffins and calcium carbonate. Further analysis revealed that the solids by themselves do not significantly contribute to emulsion stability. However, in the presence of asphaltene/resin compounds, the prominent solids such as paraffins and calcium carbonate enhance the stability of the emulsion irrespective of asphaltene/resin concentrations.
New Development Concept Lead to Five Folds Recovery Increase in a North Kuwait Field
Authors: Daoud Ahmed M. , Al-Otaibi Basel , Alkandari Dhuha
Published: March 2019

One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it.

The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery.

Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy.

Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.
Channel Fracturing Technology to Successfully Deploy Proppant Fracturing Stimulation Under Limited BHP Window for Completion Integrity
Authors: Buenrostro Adrian , Harbi Abdulaziz , Arevalo Alfredo , Carmona Jairo
Published: March 2019

Study made from the results observed over a particular application objective with one of the recently developed proppant fracturing techniques known as Channel Fracturing. This technique was used in this application to place a proppant fracturing treatment in a tight gas reservoir which pushes the installed well completion to reach its mechanical limit capabilities. Channel (or pillar) fracturing was applied in multiple cases with the intention to constrain the pressure increase commonly observed during a fracture job execution.