bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel 3D Fluid Displacement Simulations Improve Cement Job Design and Planning in the Gulf of Mexico
Authors: Bogaerts Martin , Cardozo Jimena , Flamant Nicolas , Giam David , Villar Vitor , Lehr Justin
Published: September 2019

A key to achieving zonal isolation is the complete removal of drilling mud from the annular space between casing and formation and the replacement of the mud by an appropriately designed cement slurry. Although fluid displacement simulators have been available in the industry since the 1990s, a new-generation mud removal simulator has been introduced that provides new levels of details and accuracy. The simulator can be used for all types of wells, but it especially brings value to complex wells such as those found in deepwater Gulf of Mexico.

The new fluid displacement simulator comprises a stiff-string centralization model that accurately predicts the casing standoff in a 3D wellbore. It accounts for fluid mixing inside the drillpipe and casing while the fluid travels down the wellbore and includes a high-resolution annular displacement simulator that accounts for the 3D wellbore shape and solves for azimuthal and axial flows. Thanks to these three new features, the simulator generates highly accurate and reliable results with which the cement job design can be optimized, leading to a higher probability of meeting job objectives and achieving zonal isolation.

The new generation simulator was used to design and optimize cement jobs in the Gulf of Mexico with strict cement job objectives. The results of the simulator were compared to actual results of post-job wireline cement evaluations logs. The paper includes several case studies of deepwater and shallow water cement jobs in various complex wellbore configurations. Actual cement job data were used to rerun the simulator, and the results were compared with both the prejob cement design and the post-job evaluation logs. The comparison shows that the wireline evaluation results match the fluid displacement simulations very closely when using the stiff-string centralization model in combination with the new fluid displacement simulator, therefore confirming the accuracy of the model.

Using the new stiff-string casing centralization and 3D fluid displacement simulator throughout the early planning and design of the cement job allows for an improved cement job design. The simulations highlight possible challenges early in the planning of the cement job so that any required changes or contingencies can be prepared ahead of time, thus resulting in a cement job design that meets the planned objectives.
Tight Oil EOR through Inter-Fracture Gas Flooding within a Single Horizontal Well
Authors: Fu Xuebing , Bonifas Paul , Finley Andy , Lemaster Julia , He Zhiyong , Venepalli Kiran
Published: September 2019

Over the last decade, tight oil production has become significant with the success of horizontal drilling and hydraulic fracturing. However, the recovery factor of tight oil production remains very low and no standard secondary recovery method exists after primary depletion. We propose a new secondary recovery method: to use existing hydraulic fractures (every other fracture) in a horizontal well as gas injection and oil production sites to conduct inter-fracturegas flooding within a single well.

An ideal process of this method envisions a horizontal well centered in an enclosed reservoir, where the hydraulic fractures are evenly distributed along the well, parallel to each other. If the hydraulic fractures can be effectively isolated, and injection and production can be conducted through alternate fractures at the wellbore, then highly efficient flooding patterns can be created. Key questions include: Is there adequate injectivity and productivity in a sub-microdarcy reservoir?How far are the ideal reservoir conditions from reality?How difficult is it to isolate individual fractures within the wellbore?

In addressing these key questions, first, the success of a flooding process relies on reasonable injectivity and response time between the injector and producer – in this case the injector being one hydraulic fracture and the producer being an adjacent hydraulic fracture; both economical rates and reasonable communication time between adjacent fractures are demonstrated through analytical calculations and reservoir simulations in a typical well setting; nearly 100% recovery is achieved in the reservoir units between the fractures in a miscible flooding process. Second, actual reservoir conditions are incorporated in our study, focusing on direct fracture communications; the effects are demonstrated, and comparisons among different methods are made. Finally, potential challenges in operations are summarized and current technologies are reviewed; the gaps between the current settings and the required settings are demonstrated. Economic discussions are made, indicating positive scenarios with large tolerances.

With the rapid development of tight oil reservoirs, Enhanced Oil Recovery (EOR) technologies are urgently required to improve the recovery factor beyond primary depletion. An effective flooding process may be conducted if the hydraulic fractures can be used as injection and production ports. As a first attempt to envision an inter-fracture flooding process, key aspects are defined and examined, showing promising results. Inter-fracture gas flooding may become a standard secondary recovery technique for tight oil reservoirs and add significant reserves.
State of the Art of Flow Management for Frac Plug Drillout and Flowback
Authors: Potapenko Dmitriy , Theuveny Bertrand , Williams Ryan , Moncada Katharine , Campos Mario , Spesivtsev Pavel , Willberg Dean
Published: September 2019

Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. One potential weakness of multi-stage hydraulic fracturing is that the later stages of the completion workflow – frac-plug drill out (FPDO) and flowback – cause large pressure fluctuations and transient flows through the perforation clusters that coincide with a period of low closure stress in the fractures. The proppant packs in the fractures during this period are fragile and prone to failure. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs and the subsequent well performance. In this paper the results from over 200 FPDO and flowback operations from the United States and Argentina are reviewed. These results show that maintaining a balanced flowrate during FPDO operations is critical for minimizing inadvertent damage to the hydraulic fracture network.

The FPDO flowrate balance is the difference between the coiled tubing injection and annular return flowrates. The magnitude and sign of the balance corresponds to the instantaneous flowrate through the open perforation clusters into or out of the hydraulic fracture network. A positive balance rate, or overbalance, injects fluid into the fracture system. A negative balance rate, or underbalance, produces stimulation or formation fluids from the fracture network. Sudden changes between these two regimes creates local flows that can be severe enough to flush large quantities of proppant out of the fractures. Our results show that high-frequency multiphase flowmeters simplify the process of maintaining balance (no inflow, no outflow). Furthermore, close monitoring of any imbalance that develops, and rapid control of the surface choke and injection rate, can provide for an efficient operation while protecting the integrity of the fracture system.

Early monitoring of flowback and production with a high frequency flowmeter was shown to be extremely useful technique for optimizing well productivity during well clean-up. This paper also shows how a dual energy gamma ray multiphase flowmeter successfully quantified proppant produced during FPDO and flowback. Examples of the dynamics of sand production are shown, as well as correlations to events of excessive underbalance conditions.

At the end of the paper we show that most of the highlighted problems can be solved through making changes to the well construction workflow and accounting for relationships between various well operations. Incorporation of this workflow enables early prediction of well performance issues and their efficient resolution.
The Importance of Integrating Subsurface Disciplines with Machine Learning when Predicting and Optimizing Well Performance – Case Study from the Spirit River Formation
Authors: Hirschmiller John , Biryukov Anton , Groulx Bertrand , Emmerson Brian , Quinell Scott
Published: September 2019

This machine learning study incorporates geoscience and engineering data to characterize which geological, reservoir and completion data contribute most significantly to well production performance. A better understanding of the key factors that predict well performance is essential in assessing the commercial viability of exploration and development, in the optimization of capital spending to increase rates of return, and in reserve and resource evaluations.

Machine learning models provide an objective, analytical means to interpret large, complex datasets. Generally, such models demand large databases of consistently evaluated data. As geological data is interpretive, often varying from one geologist to another, or from one pool to another, it can be difficult to incorporate geological data into regional machine learning models. Consequently, efforts to use machine learning in the oil and gas industry to predict well performance are often focused exclusively on engineering completion technology. However, this case study has utilized a regional geological Spirit River database with consistent petrophysical evaluation methodology across the entire play. This geological database is complemented with public completion and fracture data and production data to build predictive models using inputs from all subsurface disciplines.

Redundancies in the data were identified and removed. Features explaining a significant proportion of the variance in production were also removed if their effect was captured by more fundamental, correlated features that were more straightforward to interpret. The dataset was distilled to 13 key features providing predictions with a similar precision to those obtained using the full-featured dataset.

The thirteen features in this case study are a combination of geological, reservoir and completion data, underlining that an approach integrating both geoscience and engineering data is vital to predicting and optimizing well performance accurately for future wells.
Identification of Remaining Reserves Using Pulsed Neutron Logging for Pressure Determination Behind Casing in Mature Gas Condensate Reservoirs
Authors: Gray Russell , Smith Emma , Parsa Ali , Kim Yonghwee , Odusi Gbolahan
Published: September 2019

The identification of remaining reserves in mature fields is of importance to extend the field life and production life of existing wells. The Alwyn field in Quad 3 of the North Sea has been producing from the Statfjord Formation reservoirs since 1987. The initial production targeted discrete sand bodies that are separated by laterally extensive shales. The initial field pressure measurements indicated the presence of vertical barriers that have led to depleted pressures in produced intervals. Identification of present-day reservoir pressure in the gas condensate reservoirs was required to determine missed production potential within the Statfjord Formation sand bodies.

A candidate well was selected to estimate pressure behind casing by using an advanced analysis method. The method used pulsed neutron data and Monte Carlo stochastic simulation-based forward modelling to evaluate gas condensate reservoir depletion. Conventional thermal neutron capture cross section (Sigma) has low sensitivity to gas density variations, making it unable to detect reservoir pressure changes.
Effects of Confinement on Compositional Simulation in Shale Reservoirs with Thermodynamic Properties Upscaling from Pore- to Reservoir-Scale
Authors: Cui Xiaona , Song Kaoping , Yang Erlong , Jin Tianying , Huang Jingwei , Killough John , Dong Chi
Published: September 2019

The phase behavior shifts of hydrocarbons confined in nanopores have been extensively verified with experiments and molecular dynamics simulations. However, the impact of confinement on large-scale reservoir production is not fully understood. This work is to put forward a valid method to upscale the pore-scale fluid thermodynamic properties to the reservoir-scale and then incorporate it into our in-house compositional simulator to examine the effect of confinement on shale reservoir production.

Firstly, a pore-scale fluid phase behavior model is developed in terms of the pore type and pore size distribution (PSD) in the organic-rich shale reservoir using our modified Peng-Robinson equation of state (PR-C EOS) which is dependent on the size-ratio of fluid molecule dynamic diameter and the pore diameter. And the fluid composition distribution and PVT relation of fluids in each pore can be determined as the thermodynamic equilibria are achieved in the whole system. Results show that the initial fluid composition distribution is not uniform for different pore types and pore sizes. Due to the effect of confinement, heavier components are retained in the macropore, and lighter components are more liable to accumulate in the confined nanopores. Then an upscaled equation of state is put forward to model the fluid phase behavior at the reservoir-scale based on our modified PR-C EOS using a pore volume-weighted average method. This upscaled EOS is validated with the pore-scale fluid phase behavior simulation results and can be used for compositional simulation. Finally, two different reservoir fluids from the Eagle Ford organic-rich shale reservoir are simulated using our in-house compositional simulator to investigate the effect of confinement on production. In addition to the critical property shift which can be described by our upscaled PR-C EOS, capillary pressure is also taken into account into the compositional simulation. Results show that the capillary pressure has different effects on production in terms of the fluid type, leading to a lower producing Gas/Oil ratio (GOR) for black oil and a higher GOR for gas condensate. Critical property shift has a consistent effect on both the black oil and gas condensate, resulting in a lower GOR. It should be noted that the effect of capillary pressure on production is suppressed for both fluids with the shifted critical property.
PetroCup Training and Skill Testing Facility in Field Development and Production Management
Authors: Aslanyan Artur
Published: September 2019

The paper provides an overview of digital oilfield development experience gained by Nafta College [1] employing the complex PolyPlan asset simulator during a multi-year programme of PetroCup [2] interactive tournaments.

During the last few years, professional multi-disciplinary teams of 8 to 10 people from petroleum organisations based in various countries carried out few-days exercises on production and development of synthetic assets. In total, more than 20 petroleum companies, 10 petroleum service companies and 10 academic and research institutions have taken part in this programme.

PetroCup sessions had various team structures, digital reserves and regional economics to ensure realistic production conditions. Despite this variation, some statistical metrics highlight dominant trends in oilfield development strategies, including effective and ineffective ones. The results may attract interest from petroleum asset managers to assess the efficiency of corporate strategies and policies in field development planning and well and reservoir management, and eventually increase their performance.

The provided statistics are useful for managers of petroleum companies to assess the range, perspectives and value of production-related services. The PetroCup statistics can also be used by training centres and universities as an indicator of upstream trends and for maintaining the right focus in petroleum engineering curricula.
Feature Compensated Borehole Image Compression for Real-Time Logging While Drilling
Authors: Gelman Andriy , Maeso Carlos , Godet Vincent , Padin Exequiel , Tarrius Mathieu , Sun Yong , Auchere Jean-Christophe , A Adrian , Wibowo Vera , Shrivastava Chandramani
Published: September 2019

This paper presents a novel borehole image compression algorithm for real-time (RT) logging while drilling (LWD). The compression scheme is designed to optimize the critical information required for RT decision making at low telemetry bandwidths. In the proposed algorithm we estimate the structure of the image (i.e. the amplitude and phase shift of the dip) and modify the encoding dictionary based on the features. The resulting dictionary resembles sinusoidal features, thus optimizing the reconstruction of bedding or other planar features in deviated wells. The dictionary is designed using a modified version of the 2D discrete wavelet transform (DWT). This approach has a low encoding complexity and supports the integration of directional information into the transform. Since feature estimation is a challenging step, we use a classifier to identify when directional information should be added to the transform or whether a conventional implementation is used. The algorithm has been implemented in both oil- and water-based mud LWD imager tools, where the low encoding complexity has facilitated the implementation in legacy tools with limited computation resources. We present field test results comparing the borehole images from RT and recorded mode (RM) data from one of the industry’s first RT LWD resistivity images obtained from a well drilled using oil-based mud.
Tunable Friction Reducer Improves Operational Efficiency and Increases Production in the Eagle Ford
Authors: Luster Jared , De Sario Christine , Khan Shafeeq , Long Jeffrey
Published: September 2019

This study will demonstrate a comparison of completion fluid designs in operations and production across several pads in Gonzales and Lavaca counties in the Eagle Ford Basin. The use of tunable friction reducers (FRs) significantly improves completion efficiency and production. The paper also illustrates how tunable FRs provide greater versatility at the wellhead by replacing multiple fracturing fluid systems such as conventional friction reducer and linear gel with a single additive.

When conventional FRs prove inadequate in slickwater designs, subsequent HVFR and linear gel designs are utilized. This study demonstrates that tunable FRs provide the flexibility to be run at lower concentrations as an effective and efficient friction reducer. Should the slickwater treatment be insufficient, the FR concentration can easily be increased to achieve improved results for pressure reduction and sand placement while minimizing chemical additives and equipment on location. In addition, this tunable FR is engineered with breakable linkages that minimize formation damage to help improving production.

Tunable FRs can be run at less concentration compared to conventional FRs while delivering the same friction reduction as slickwater. Increasing the concentration produces a higher viscosity similar to that seen in linear gel. This flexibility is achieved with less equipment and additives and can be executed on- the-fly while pumping. This design has enabled an operator in the Eagle Ford to complete more stages with less shutdowns and screenouts. Eliminating equipment and extra additives simiplified logistics, reduced the footprint and equipment-related non-produtive time (NPT). Overall, production results taken over the first 12 months show that wells completed with the tunable FR had noticeably superior performance in cumulative production, which is normalized by lateral length. These improvements can be attributed to the proppant transport capabilities and the breakability of the tunable FR, which minimizes residue left in the formation and, in turn, provides greater regain conductivity.

Additional benefits include simplified delivery and smaller jobsite footprint requirements, which lead to significant cost savings. The tunability of the FR allows it to be administered on the fly while pumping, giving design change flexibility, enhancing overall operational efficiency. Since there is no need of hydration unit or dry-on-the-fly (DOTF) unit used for hybrid linear gel design, fewer NPT hours due to equipment breakdown was seen on location.
Machine Learning of Spatially Varying Decline Curves for the Duvernay Formation
Authors: Bakay Alexander , Caers Jef , Mukerji Tapan , Miller Patrick , Cartier Cheryl , Briceno Arnulfo
Published: September 2019

The focus of this paper is on Duvernay shale formation in Alberta, Canada. The objective is to provide, based on existing data of production, completion and geological parameters, an automated machine- learning approach to determine the spatial variation in decline type curves for gas production. This model will enable the prediction and uncertainty quantification of production profiles for new target wells or areas in the basin.

The project is based on publicly available monthly production data from most of the producing wells of the Duvernay formation. We use k-means to cluster 273 wells, using geological parameters (thickness, porosity, etc.), completion parameters (horizontal section length, proppant volume, etc.), spatial location, fluid window, and production curves. Based on the clustering results, a machine learning classification is used to draw distinct geographic regions, within which the combination of geological, completion, and production factors is fairly similar. A support vector machine approach is used to create maps of clusters and quantify its uncertainty.

In addition, functional classification and regression trees (CART) is used to indicate the most important/sensitive factors that should be used for clustering.

The results show that the unsupervised method, k-means, performs equally as well as the supervised CART method. The methodology is flexible and allows for quick changes in the variables used in clustering; the transfer to another dataset or basin is straightforward.
Advanced Real-Time Analytics Allow Performing the Shallowest Injection Test Ever on the Norwegian Continental Shelf NCS – Rational, Planning, Execution and Results
Authors: Stueland Eirik , Øverland Alf M. , Persaud Mira , De Leonardis Donato , Sanfilippo Francesco , Santarelli Frederic J.
Published: September 2019

Reservoirs in the Barents Sea are several times shallower than in other parts of the NCS, essentially due to recent uplift and erosion of younger sediments. A proper understanding of their geomechanics is considered paramount for their successful development. In turn, the lack of any available analogue makes the proper in situ measurement of key parameters compulsory.

The paper describes the planning and execution of an appraisal well solely dedicated to the purpose of geomechanics data acquisition in the shallowest oil reservoir on the NCS – i.e. coring, logging, XLOT and injection testing. It focuses on the operations conducted in the oil reservoir itself, which included an entirely novel multi-cycle injection test aimed at estimating the large-scale thermal stress coefficient of the formations around the well – i.e. the impact of the injection temperature on the fracture pressure of the formations.

Every operation in the well was challenging due to the sea depth being about twice that of the overburden thickness and to the formations being quite consolidated, which was met by careful iterative multidisciplinary-planning. The equipment was often taken to its limit and sometimes extended beyond its standard use – e.g. the metering systems.

The injection test itself could not be performed traditionally – i.e. use of surface data and downhole memory gauge. Instead, the downhole gauge data were sampled, pumped out and transferred to a remote site where real time advanced analytics was used to ensure that safety criteria were always met throughout the operation in terms of vertical fracture propagation and lack of reservoir compartmentalisation. In addition, this allowed adjusting the planned injection schedule to the exact formation's response, which could not be fully quantified ahead of time.

All the targets of the appraisal well were met. The injection test – i.e. the shallowest on the NCS and perhaps worldwide in an offshore environment – was performed successfully. Its main results are considered essential for a possible future field development – e.g. the injectivity is confirmed and, in addition, a significant thermal effect is proven.

The series of novel technologies deployed in the extreme environment presented in the paper can easily and beneficially be extended to more traditional reservoirs. This concerns performing multi-cycle injection tests on appraisal wells on a systematic basis to prepare and optimise the development plan, real-time monitoring through advanced analytics and adjustment of these tests, start-up of injection wells during field development, monitoring and optimisation of water injection schemes, etc.
Effect of Asphaltene Precipitation and Deposition on Miscible Viscous Fingering in Porous Media — High-Resolution Nonlinear Numerical Simulations
Authors: Sabet Nasser , Mohammadi Mohammadjavad , Zirahi Ali , Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal
Published: September 2019

This work focuses on modeling the miscible viscous fingering in porous media accounting for asphaltene precipitation and deposition. The mass balance equations for solvent and asphaltene are defined, and the highly nonlinear system of equations is solved numerically through hybridization of compact finite difference and pseudo-spectral methods. We explain how asphaltene precipitation and the resulting formation damage influence the growth of viscous fingers.

To conduct our analysis, we use the experimental data for the amount of asphaltene precipitation at different solvent mass fractions and also oil viscosity at various asphaltene and solvent contents. This data is measured in our lab and is used as input for the nonlinear numerical simulations. For these simulations, the conventional finite difference schemes cannot be applied as they suffer from the excessive computational time and most importantly, numerical dispersion. Therefore, we employ hybrid techniques to benefit from the high accuracy of spectral methods and capture the nonlinear dynamics of fingerings on very fine grids.

Hydrocarbons such as light n-alkanes are widely used as diluents in the production and upgrading of heavy oils. The addition of a diluent to heavy oil or bitumen alters the chemical forces acting within the mixture, leading to the precipitation of asphaltenes. It is hypothesized that precipitation of asphaltene from oil changes the viscosity behavior of the mixture, influences the dynamics of viscous fingering, and therefore affects the oil recovery. Moreover, asphaltene deposition alters the porosity and permeability of the porous media and might modify the flow paths, leading to possible formation damage. Our results show that asphaltene precipitates are mostly accumulated in the contact interface between the solvent and oil. The major asphaltene deposition occurs along the growing fingers leading to permeability reductions up to 30% in the studied cases.
In-Depth Understanding of the Ultra-Low-Interfacial-Tension Foam Flood in Oil-wet Fractured Media through Simulation with an Integrative Mechanistic Foam Model
Authors: Luo Haishan , Mateen Khalid , Ma Kun , Ren Guangwei , Neillo Valerie , Blondeau Christophe , Dong Pengfei , Puerto Maura , Biswal Sibani , Hirasaki George
Published: September 2019

Recovering oil from oil-wet matrix in fractured carbonate rocks is highly challenging. Recent experiments have indicated that ultra-low-interfacial-tension (ULIFT) foam flood could significantly boost the oil recovery from such rocks. However, there is limited information available about the foam and the microemulsion transport in the fractured system to extract the oil from low permeability matrix. Adaptation of this technology in the field would not be possible without a good understanding of the process.

The aim of this work is to model and history match the ULIFT foam flood in fractured carbonate cores for further gaining insight into the complex four-phase flow. The model was set up based on a group of experiments using cores split lengthwise to simulate axially confined fractures. Pre-generated foam was tested in this system due to the lack of in-situ generation of foam in the straight fracture at the core scale. Various foam coalescence mechanisms, with/without oil, were modeled, and a dynamic-texture population-balance foam model was developed for this purpose.

Our model incorporates the effects of oil and permeability as well as the coexistence of foam and microemulsion on the foam apparent viscosity. The model is able to reasonably well history match both the oil recoveries and the total pressure drops of the ULIFT foam floods in fractured carbonate cores. More impressively, the modeling results agree very well with the pressure gradient of each section of the core, indicating that the spatial variation and distribution of the foam texture are largely captured. The simulation results also show that the pre-generated foam greatly resists the fluid flow in the fracture close to the injector side and enhances the diversion of injected fluids into the matrix layers, leading to improved oil displacement. The resulting oil crossflow from the matrix to the fracture destabilizes the foam at the foam front thereby slowing the transportation of foam in the fracture. Additional case studies suggest that significantly more oil can be recovered if the foam destabilization by oil could be reduced/mitigated.

Test results disclosed in this paper demonstrate for the first time the successful modeling and history-match of ULIFT foam floods in fractured rocks. Valuable insight into this complex process has been gained through this innovative research. This is of great value with respect to the further optimization of the corefloods, the design of the surfactant formulation, and the feasibility of applying this new technology to the field scale.
Large Deployment of Multiphase Flowmeters in an Unconventional Field
Authors: Theuveny Bertrand , Moncada Katharine , Roth Melissa , Wu Yvette , Mikovich Michael , Guichard Anna
Published: September 2019

abstract

The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest.

There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells.

A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility.

The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions.

Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements.

The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased.

A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed.

The reduction of HSE risks through a better management of field operators is also assessed.
Directional Measurements While Drilling
Authors: Karvinen Kai , Hoehn Oliver , Schulze Steffen , Wassermann Ingolf
Published: September 2019

Real-time downhole estimation of inclination and azimuth is desirable for improved wellbore quality, better management of the drilling process with regard to wellbore hydraulics and drilling dynamics, and is a prerequisite for advanced directional drilling services such as downhole azimuthal hold mode and surface-based automated trajectory control. However, reliable estimation of azimuth while drilling remains a challenging problem, particularly in certain orientations in harsh drilling environments. We present a detailed problem description and describe the approach used to develop a new algorithm to estimate azimuth while drilling, which offers significant improvements over existing algorithms. Such an algorithm will form the foundation for advanced drilling system automation services, such as automated trajectory drilling.
Validation of the Utility of the Contrast-Agent-Assisted Electromagnetic Tomography Method for Precise Imaging of a Hydraulically Induced Fracture Network
Authors: Ahmadian Mohsen , LaBrecque Douglas , Liu Qing Huo , Kleinhammes Alfred , Doyle Patrick , Fang Yuan , Jeffrey G Paine , Lucie Costard
Published: September 2019

Characterizing hydraulically induced fractures—height, length, orientation, and shape—is key to understanding reservoir performance. Our previous work has focused on the comparison of the state-of-the-art geophysical techniques currently used in hydraulic fracture imaging (microseismicity, tracer, tiltmeter, and distributed acoustic and temperature sensors) to perform a comprehensive set of electromagnetically active proppant (EAP)–assisted tomography methods (LaBrecque et al., 2016; Ahmadian et al., 2018). In our latest study, we conducted a field pilot at The University of Texas at Austin Bureau of Economic Geology's Devine Test Site, located approximately 50 miles southwest of San Antonio, Texas. Following hydraulic fracturing with EAP, we detected a measurable electromagnetic (EM) fracture anomaly at a depth of 175 ft (~53 m) by use of a set of four PVC-cased wells equipped with electrode arrays for single hole, hole-to-surface, and cross-hole electrical resistivity tomography. Because of relatively low overburden pressure, and as designed, fractures grew horizontally and appear nonaxisymmetric about the center injection well (fracture image looks like a human foot). This design allowed us to verify our results with drilling and logging of eight vertical wells. In addition, we cored two wells, and these samples further corroborated the presence of EAP proppants at the predicted depth. Together, these results conclusively corroborate the accuracy of our EM inversion models to within 5 ft of the physical edge of the EAP-filled fracture anomaly. We are currently using results from our ongoing geophysical surveys to refine and verify the efficiency of forward and inverse EM modeling codes for open-borehole and through steel casing scenarios. This paper describes the ground-truth validation of our model predictions, as well as the future direction of our research.
First Digital Intelligent Artificial Lift Production Optimization Technology in UAE Dual-String Gas Lift Well - Business Case and Implementation Plan
Authors: Alshmakhy Ahmed , Al Daghar Khadija , Punnapala Sameer , AlShehhi Shamma , Ben Amara Abdel , Makin Graham , Faux Stephen
Published: September 2019

Objectives/Scope

Majority of the world's gas lifted wells are under-optimized owing to changing reservoir conditions and fluid composition. The gas lift valve (GLV) calibration is required with changing conditions. Apart from that, an allowance needs to be kept so that the valve change remains valid for longer time. Compounding this, when adjusting gas lift parameters, it was not easy for the gas lift operator to make data-driven decisions to assure continuous maximized production. These challenges are further amplified with dual completion strings: fluctuating casing pressure; unpredictable temperatures due to the proximity of the two strings; and inability to individually control the injection rates to each string. String dedicated to the formation with lower productivity and reservoir pressure tends to "rob" gas from other string. Operating philosophy in such cases end up producing from one string. Production optimization in such cases requires frequent intervention with attendant costs and risks thus presents an opportunity to re-imagine gas lift well design.

Methods, Procedures, Process

ADNOC in collaboration with Silverwell developed a Digital Intelligent Artificial Lift (DIAL) system, which consists of multiple port mandrels to be placed at GLV depths. These mandrels are connetced to the surface operating system with a single electrical cable. The ports can be selectively opened or closed by sending an electric signal from the surface unit. In addition, pressure and temperature sensors are also placed which help record these parameters in real time. Such a system enables the choice of depth, injection rate, loading and unloading sequence controlled from the surface. Realtime optimization is possible as pressure/temperature data helps draw accurate gradient curves. This system makes gas lift optimization possible in dual gas lift wells.

Results, Observations, Conclusions

It has been estimated that this technology delivers a production increase approaching 20% for single completion wells, and exceeding 40% for dual-string gas lifted wells. Recognizing this opportunity, a business case and implementation plan were developed to pilot a dual-string digitally controlled gas lift optimization system.

Novel/Additive Information

This paper will describe, the screening phase, business case preparation, risk assessment and validation process, leading to this 1st worldwide implementation of a fully optimized dual completion gas lifted well. Implementation plan of novel digital gas lift production optimization technology in an onshore dual completion well. The completely original approach increases safety, efficiency, operability and surveillance.
Machine Learning Forecasts Oil Rate in Mature Onshore Field Jointly Driven by Water and Steam Injection
Authors: Kubota Leonardo , Reinert Danilo
Published: September 2019

In this paper, we tackle an old problem – production forecast - using techniques that are relatively new to the reservoir engineer toolbox. The problem at hand consists of forecasting oil production in a mature onshore field simultaneously driven by water and steam injection. However, instead of turning to traditional methods, we deploy machine-learning algorithms which will feed on a plethora of historical data to extract hidden patterns and underlying relationships with a view to forecasting oil rate. No geological model and/or numerical reservoir simulators will be needed, only 3 sets of time-series: injection history, production history and number of producers. Two Machine-Learning algorithms are used: linear-regression and recurrent neural networks.
Industrial Scale Demonstration of Ceramic Membrane Filtration for Produced Water Treatment
Authors: Ishikawa Fuyuhiko , Mima Satoru , Nakamura Arata , Shinohara Masayo
Published: September 2019

Water production from oil and gas fields has been more and more increasing globally, and thus the treatment and the reuse of produced water has become one of the top issues in oil and gas industry. Produced water re-injection (PWRI) to reservoirs for pressure maintenance or water flooding is an environmentally-friendly scheme over disposal options. Because solid particles, bacteria, as well as residual oil can cause plugging of the pores in the formation rock resulting in deterioration of oil recovery, PWRI to "tight" or low permeable reservoirs requires high levels of removal of these constituents. In addition, there is also a growing interest of removal of dissolved salts from the produced water for the beneficial reuse. This also requires an advanced filtration as pretreatment to desalination by reverse osmosis (RO) or evaporation. For both of these applications, microfiltration (MF)/ultrafiltration (UF) technologies using ceramic membranes are considered as a very effective solution because ceramic membranes offer high hydrophilicity, relatively low fouling by oil-in-water, and broad chemical and thermal compatibilities. An industrial scale produced water treatment demonstration plant has been installed in an oilfield to test the performance of ceramic MF membranes. The plant includes a crossflow filtration system which accommodates commercial ceramic membranes (180mm Dia., 1,500 or 1,000mmL) followed by RO equipment. The demonstration test was performed for seven months in 2017. Through the seven months of the field demonstration, protocols for sustainable operation were developed under field conditions in which feed water qualities varied very widely in terms of concentration of oil & grease and other foulants. The filtrate contained suspended solids (SS) and oil & grease not higher than 1 mg/l and 10 mg/l, respectively, at all times during the test period. Therefore, it has been proven that the ceramic membrane filtration can be very effective for alleviating plugging risk when applied to PWRI in tight reservoirs. Silt-density-index (SDI) of permeate, an indicator of RO feed water quality was not higher than 3.0 and the average was 1.6; this indicates the membrane-filtered water is appropriate for the RO feed.
Application of Multiphase-Multilayer Pressure Transient Analysis for Well Monitoring and Reservoir Management - A Case Study of Deep-Water Offshore GoM Reservoirs
Authors: Ajayi Arashi , Fassihi Reza , Wrobel Adam , Allouache Aimon , Johnson Mark , Bryant David , Akajagbor Collins
Published: September 2019

Well diagnostics in deep, offshore GoM are vital in order to interpret any issues related to productivity losses. This is especially important since any intervention in such wells is very costly. Multiphase flow is amongst leading causes of well productivity loss. This paper presents an integrated workflow that provides a solution to the challenge of quantifying multiphase PTA results in single and multiple commingled production cases. The workflow is used to monitor the performance of several wells over an extended period in a deep-water offshore reservoir under water/aquifer drive. It builds on a succession of PTA tests starting from single phase flow until water breakthrough and beyond. The results of historical PTA provided meaningful insights that were used as basis for actions that led to well and reservoir performance optimization.
Modular Functions of Electronic Frac Sleeve
Authors: Walton Zachary , Fripp Michael , Merron Matt
Published: September 2019

A new electronic sliding sleeve has been developed for hydraulic fracturing that combines the best features of traditional sliding sleeves and plug and perf techniques. This battery-powered electronic sliding sleeve provides the operational efficiency of sliding sleeves in an unlimited number of zones. The firmware, electrohydraulic lock, and electronics package in this new sliding sleeve help enable a range of operational functions for use in hydraulic fracturing.

Traditional sliding sleeves use a series of progressively sized balls that shift sleeves by landing on progressively sized baffles. An electronic sliding sleeve creates a monobore construction with the same inside diameter bore in each sleeve and helps enable treating of an unlimited number of zones. The electronics in the sliding sleeve helps eliminate the mechanical complexity of other monobore fracturing tools. The firmware and electronic package enable a modular approach to electronic sleeve design. Therefore, one frac sleeve chassis design can be used for many of the different types of sleeve tools in the well completion, and the firmware that drives the electronics is modified for each respective type of tool.

Using combinations of the electrohydraulic lock, electronics package, and firmware can enable the design of all the tools necessary to complete a wellbore. The standard firmware, used for a single point entry sleeve, operates by counting the correct number of frac balls. When the correct count is reached, the electrohydraulic lock is released, enabling sleeve movement or zonal isolation deployment. A modification can be made to the firmware to have the tool actuate on the next count, rather than the initial count, and delay the time at which the electrohydraulic lock is released. This type of architecture lends itself to the design of multi-entry sleeves. The sensor can also be eliminated by using the delay feature in the firmware of the electrohydraulic lock, programmed in weeks. This type of architecture also helps enable the design of a toe sleeve.

Having the ability to implement slight modifications to the components that make up the sliding sleeve enables design flexibility and modularity for all sleeve type tools necessary to complete a wellbore. This type of system architecture helps decrease operator risk and ease design constraints while performing multiple functions downhole.