bluuebunny/crossref_metadata_2025 huggingface dataset:
Unique Backup Cutter Layout Method Leads to Step Change in Bit Durability and Performance when Transition Drilling Through Hard Limestone Formations at High Inclinations
Authors: Vrnak Kyle , Boutot Franck , Anderle Seth
Published: October 2018

In the mature fields in Norway's North Sea, extended-reach drilling (ERD) well designs were implemented to reach distant reservoir target zones. Resulting from this change, the 12.25-in. overburden section, which drills through mostly shale with various hard and thin dolomitic limestone sections, had to be modified from a 5,000- to 7,000-ft vertical section to a 10,000- to 12,000-ft section at a tangent inclination anywhere from 35 to 70°. Drill-bit designs that used to drill the vertical overburden section consistently in one run currently require up to three bits to complete the modified tangent sections caused by excessive damage to the diamond cutting structure.

An extensive study into the offset ERD wells and corresponding bit dull conditions helped identify that the cutting structure damage originated from high-point load impacts to the shoulder of the bit while transitioning through the thin, hard dolomitic limestone formations; the damaged cutters were being tangentially overloaded. Through further bit modifications, it was determined that this type of damage could not be addressed using typical bit design modifications (e.g., increased cutter density, increased blade count, etc.); therefore, a unique design solution was developed and implemented.

This solution involved combining analytical simulations and a dull condition analysis to develop an improved method for using the backup cutting structure to support the high tangential loading on the primary cutting structure during hard, high-inclination transitions. In most dual-row cutting structure designs, the backup cutters are on the same radial position as their parent primary cutters and are underexposed, engaging the formation only at a specific depth of cut or after the primary cutters are worn down a certain amount. When positioned as such, the backup cutters do nothing to support the tangential loading on the primary cutters. By moving the backup cutters actively on profile with the primary cutters and offsetting them to their own radial positions, the backups could now actively support the high tangential loads occurring on the primary cutters when engaging the hard dolomitic limestone.

This simple but unique modification enabled the bit to handle the transitions and drill the entire next 11,000-ft+ ERD section in one run while also providing the fastest rate of penetration (ROP) to date, with an increase ranging from 30 to 40% compared to previous runs. The success has been repeated a dozen more times since, each time providing a new record ROP for an ERD section. The improved dull condition could also allow for more efficient designs in the future for further improvements to drilling performance. The successful reduction of tangential impact damage could have implications for various bit designs globally that incur a similar dull condition.
Operational Designs and Applications of MPD in Offshore Ultra-HTHP Exploration Wells
Authors: Yin Qishuai , Yang Jin , Zhou Bo , Luo Ming , LI Wentuo , Huang Yi , Sun Ting , Hou Xinxin , Wu Xiaodong , Wang Junxiang
Published: October 2018

The South China YQ Basin with 15 trillion cubic meters natural gas is typical of ultra high temperature-high pressure (ultra-HTHP) with the highest bottomhole temperature (BHT) at 249°C, the maximum bottomhole pressure (BHP) at 142MPa and the extremely narrow pressure window. Therefore, there are kinds of technical challenges during drilling there. In recent years, the managed pressure drilling (MPD) has been successfully applied in the basin with risks and well cost reduced instead.

The operational designs of MPD consist of three parts: the precise calculation of drilling fluid equivalent circulating density (ECD), the optimization of operational parameters and the well control. The first part includes four models: the wellbore temperature field model, the drilling fluid equivalent static density (ESD) model, the drilling fluid rheological property model and the effects of cuttings concentration on ECD. The second part is the determination of the two key operational parameters: the mud weight (MW) and the surface backpressure (SBP). The third part is the plans of three cases: downhole accidents, equipment failures and termination conditions of MPD.

The first part includes four steps: establish the instantaneous wellbore temperature model based on the convection and thermal conductivity theory by dividing the wellbore into five areas; establish the ESD model by considering the elastic compression effect of HP and thermal expansion effect of HT; establish the drilling fluid rheological property model based on the Herschel-Buckley model by considering the effect of ultra-HTHP on dynamic shear force, consistency coefficient and liquidity index; consider the effects of cuttings concentration on ECD based on the solid-liquid two-phase flow. The ECD model is established based on above models. The second part includes two steps: determine the MW based on the critical pressure constraint principle by the operational window simulation of different well depth and fluid volume; determine the SBP of pump-on and pump-off by considering the rated operating pressure of the equipment, the calculated pressure loss and the 0~1MPa higher BHP than formation pressure. The third part includes three steps: make the emergency measures against downhole accidents by well control matrix; make the emergency measures against the failure of equipment such as rotating control device (RCD); determine the MPD termination conditions such as drilling big cracks.

The MPD is successfully applied to X gas field featuring offshore ultra-HTHP. The casing structure is optimized from 7-8 layers to 5 layers and the well is drilled in the micro pressure window of 0.01~0.02sg without accidents. Additionally, the non-productive time (NPT) decreases by 60% and the well cost is obviously reduced. Generally, the MPD yields time and cost savings for tomorrow's market.
Process, People and Technology: Synergy Leads to Performance Improvement, a Case from South Iraq
Authors: Mee Michael , Dementyev Alexander
Published: October 2018

Operators and service companies alike gain from improvements in efficiency. However, many organizations fail to look beyond technology and in depth at all the minute processes that become part of drilling a well. Delving in to these processes, applying area appropriate technology and putting the right people in place to execute the workflow is not enough. Synergy between all three needs to take place.

This paper illustrates through examples and figures, how an integrated approach to engineering and operations focused on the incorporation of field appropriate processes, people and technology for a given area will lead to increased efficiency in drilling operations and improved HSE performance. Specifically, in Southern Iraq. The paper will focus on three areas.

First, people and process, what the proper level of expertise is and what continuous improvement processes were these people trained to use in the field and in the office? Even with the drive to mechanization and automation the drilling industry is currently heavily reliant on people and their input. People are unpredictable, putting the proper processes and workflows in place introduces some predictability and consistency to well delivery. Keeping these processes focused and minimized allows creative problem solving to still be of value.

Second, technology and process, the upstream oil and gas industry has been historically resistant to technology chances, but eventually adopting relevant technologies after an extended trial period. Using a defined process to evaluate technology (both software and tools) allowed this team to select area appropriate technology from the vast array of new technology available. On the other hand, there were times when legacy technology was best suited to the application in this field.

Last, integration processes, how was the above brought to bear on a project in South Iraq and how was it all blended together in such a manner as to produce a net ~40% improvement in overall well times? How should managers and team members treat integration? Where and when does the value of integrated processes begin to take effect?

This paper will discuss the methods used, the technology implemented, the processes designed to manage performance, and the results on the project will be laid out in further detail.
Cost and Operation Optimisation for Downhole Tractor Conveyance for Perforating in ERD Wells by Using Wireline Multistage Pressure Deployment System
Authors: Ibrahim M. Z. , Ibrahim M. M. , Findlay C. , Techanukul T. , Noor Hassim M. F. , Wongyaowarat K. , Ramli M. R.
Published: October 2018

The recent infill wells of MDE were drilled and completed with the most complicated architecture in CPOC. They were designed with high inclination reaching almost 87 degree and 2.6 ERD ratio in order to optimize hydrocarbon recovery from multi-stacked reservoirs within the area. The study, driven by cost effective initiatives, compared wireline tractor conveyed perforation (run in normal and reverse deployment modes) and coiled tubing conveyed perforation (again, run in normal and reverse deployment modes). The aim of this study is to provide the most efficient technique to achieve maximum hydrocarbon returns with low operational costs and minimum risks. The scope of this study includes consideration of well test requirement and net over gross ratio of perforation interval.

Four (4) options are feasible to complete these high inclination and long departure wells: wireline tractor-conveyed perforation (run in normal and reverse deploy modes); and coiled tubing-conveyed perforation (run in normal and reverse deploy modes). The analysis includes several factors such as different rig-up height, perforation depth accuracy, perforation flexibility, operation time, and tool requirement. Generally, the job executions begin by rigging up the perforating gun into wireline or coiled tubing conveyance, then running in hole to designated target depths.

The wireline tractor with reverse deployment and multiple-firing system was the chosen method, deployed for the first time in slim hole, high inclination and long departure wells within Joint Development Area (JDA), Gulf of Thailand. This conveyance method proved to provide a 68% reduction in numbers of runs, with cost reductions of 25% and 50% in operating day and operating costs respectively. Perforating operations in all three wells were successfully completed with 269 meters total perforation length. The tractor operated for a total distance of 94 kilometers which is considered as the longest tractor marathon in a campaign worldwide.

The utilization of tractors for this campaign is considered as a record breaking for the operators and contractors. As a result, the wells have been able to deliver the gas as expected and fulfill the nomination to buyer demand.
Investigation on Hydraulic Fracture Initiation and Propagation with LPG Fracturing in Shale Formation based on True Tri-Axial Laboratory Experiments
Authors: Zhang Ruxin , Hou Bing , Zeng Yijin , Zhou Jian , Li Qingyang
Published: October 2018

Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively.

In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed.

The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure.

The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.
Evaluation of Novel Surfactant for Acid Stimulation and EOR Treatments
Authors: Bin Omar Abdulrahman , Al Moajil Abdullah A. , Al-Darweesh Sajjad , Al-Rustum Abdullah
Published: October 2018

This paper represents a study of the application of nano-surfactant in the acid stimulation and EOR operations. The performance of the novel surfactant was compared with commercial alcohol ethoxylate surfactants. Different acidizing additives were added to the surfactants under study to evaluate their behavior using surface tension measurements. A negative behavior of the nano-surfactant with corrosion inhibitor, H2S scavenger, and iron control and reducing agents were observed. Regardless of the effect of these additives on the surfactant performance, the nano-surfactant still provides a better performance overall compared to commercial alcohol ethoxylate surfactants. Interfacial tension experiment of the nano-surfactant with condensate samples was performed giving an average IFT of 8 dynes/cm at 160 °F.
Understanding Stress Effects on Borehole Acoustic Waves for Unconventional Shale Reservoirs
Authors: Lei Ting , Zeroug Smaine , Sinha Bikash , Bose Sandip
Published: October 2018

Acoustic velocities in many sedimentary rocks exhibit stress sensitivity. This behaviour has been validated through experiments, observed from field measurements, and is described by the acoustoelastic model. Inversion methods based on this model have been developed to characterize stresses, and provide the basis for non-destructive means to calibrate stress profiles. Observation of borehole sonic dipole dispersion cross-over signatures serve as an indicator of stress-indcued anisotropy – an effect that has been validated theoretically through 3D numerical modeling. Such modeling has been carried out for sandstone and cabonate rock and less so for shale rock. To understand the stress effects on sonic measurements in wells traversing unconventional reservoirs, we carry out simulations of the borehole sonic measurement in shale formations subjected to subsurface stresses.

To this end, we have developed and used a new 3D modeling code based on the finite-difference time domain scheme in a cylindrical coordinate borehole system. The linear and nonlinear elastic constants of shale core samples from laboratory experiments are used as inputs to the modeling. Synthetic waveforms are processed using a modified matrix pencil algorithm to estimate the borehole sonic mode dispersions and their sensitivities to the stress-induced anisotropy.

For a vertical well, our modeling results demonstrate new dispersion signatures associated with certain shale formations. The borehole flexural dispersions at the two canonical horizontal stress directions split at high frequencies whereas they overlay at low frequencies. The split at high frequencies is caused by near-wellbore stress concentrations and the overlay at low frequencies is owing to the typical shale laminated lithology. The modelled dispersion signatures were also observed from processing of field data acquired with both sonic and ultrasonic tools in a vertical well in a laminated unconventional shale formation. The ultrasonic tool measures compressional and shear slownesses azimuthally at radial depth of about 1 in. from the borehole surface. The presence of imbalanced stresses is confirmed in adjacent intervals from symmetric breakouts. In a 20-ft interval not exhibiting breakouts but surrounded by intervals with breakouts, the ultrasonic tool also measures the compressional and shear slownesses with an azimuthal quasi-sinusoidal variation caused by stress concentrations around the borehole. On the other hand, sonic waveforms recorded by cross-dipole measurements in the same interval show high-frequency splitting dispersions as reproduced by the modeling. Taken together, these results confirm the existence of a new sonic dipole signature caused by the subsurface stresses in vertical wells traversing unconventional shale reservoirs.
Foam Hydraulics Modeling for Sand Cleanout in Low Bottom Hole Pressure Wells
Authors: Rao Sai Sashankh , Antunes Morgado Nicolas , Kulkarni Kaustubh Shankar , Sun Huafei , Arnold Allen
Published: October 2018

As foam is significantly less dense than water, and it can have a rheology capable of holding sand, it is an attractive fluid for sand cleanout in completions of low bottom hole pressure (i.e. underbalanced) wells. However, predicting the behavior of foam can be technically challenging, and mobilizing equipment to perform foam operations can be expensive. The primary objective of this work is to demonstrate how a foam hydraulics model can be used to determine the feasibility of performing a foam operation for a given well and to maximize sand cleanout rate in wells where feasible.

Foam is a compressible fluid characterized by its quality (ratio of gas volume to total (gas+liquid) foam volume) and works as a stable fluid within a certain range of quality. Foam’s quality depends on its pressure. As pressure increases, foam’s quality decreases due to compression of gas in the foam. In this work, we make simplifying assumptions to develop a one-dimensional steady-state hydraulics model for foam flow through coiled tubing and then back up the annulus of deviated wells that contain a sand bed. The hydraulics model for foam captures foam’s compressibility, non-Newtonian rheology, non-linear hydrostatic pressure profile, friction pressure including slip velocity, the effect the geothermal gradient has on the foam, and the effect suspended sand has on the foam. We obtain results for the foam pressure and quality at various locations along the coiled tubing and wellbore annulus, as well as the time it takes to circulate foam through the coiled tubing and annulus. In more detail, we obtain results for the hydrostatic pressure and frictional pressure drop for different sections of the coiled tubing and annulus. The results show that an increase in foam quality (i.e. increased ratio of gas to liquid) results in a decrease in hydrostatic pressure (lighter foam) but an increase in the frictional pressure drop (more viscous foam), following experimental evidence. The bottom hole pressure of foam is a function of the hydrostatic pressure and frictional pressure drop in the annulus. Thus, as the foam quality increases, the bottom hole pressure can increase, decrease, or stay the same. The results bring out the non-intuitive behavior of foam and demonstrate how challenging it can be to control a foam hydraulics system. We compare our model predictions for the total pressure drop across the coiled tubing and annulus to field data and obtain reasonable agreement. Finally, we describe how our model can be applied to achieve the primary objectives of this work (described above) through two examples. The examples demonstrate how a foam hydraulics model can be used to support and guide operational decisions.
Strategic Growth in Oil and Gas: A Capabilities Perspective
Authors: Capello Maria Angela , Dashti Qasem , Al-Khamees Waleed , Mohammed Moussa , De Sousa Maria J.
Published: October 2018

Kuwait Oil Company (KOC), one of the most important National Oil Companies (NOC) in the world, is growing in every sense, as the State of Kuwait is seeking to boost its oil production capacity by 2040, in line with the new approved strategy of Kuwait Petroleum Corporation. This growth into the future entails a shift from primary extraction to more complex settings, where new fields are produced simultaneously with others submitted to water flooding, EOR and Steam Injection, in what constitutes one of the biggest challenges ever faced by the company, due to the short timelines involved.

The company has a variety of technological partners that include International Oil Companies (IOC), to further support the 2040 strategy of the corporation. This strategic growth vision, not exempted of an increasing breath of challenges, is accompanied by a focused effort in building new technical capabilities in the personnel, and in gradually transforming the way the training plans shape the professional profiles and set the paths for ensuring the specialized skills and expertise that will be needed.

This paper describes how KOC is collaborating with an IOC, for uplifting and accelerating the training of its personnel, with the aim of enabling the availability of critical expertise needed to ensure production targets. Selected examples will detail how this cooperation NOC-IOC has been fruitful in enhancing competencies and training workflows. The teams involved from both sides of the spectrum experienced interesting challenges, and did not shy away from applying tactics of management of change to support the evolving talent development ecosystem.

An emphasis will be placed in describing why elements like cultural nuances, corporate legacy, communication, alignment and integration are considered key in the implementation of the training strategies. With a well-established KOC competency-based training scheme, and after several years of fruitful exchanges with the IOC, the uplifts achieved in talent development schemes have shaped a transformation journey, with specific results worth sharing.
Optimal 3D Reservoir Insight with a New Ultradeep-Reading Azimuthal LWD Resistivity Tool
Authors: Campbell Alan , Beeley Hugh , Bittar Michael , Walmsley Arthur , Hou Junsheng , Wu Hsu-Hsiang Mark
Published: October 2018

A new azimuthal electromagnetic (EM) logging-while-drilling (LWD) tool has been developed with multiple tilted antennas to measure three-dimensional (3D) electromagnetic fields. Multiple field trials successfully demonstrated the ultradeep detection range of more than 200 ft (60 m) with various transmitter-to-receiver spacings and operating frequencies, providing valuable geomapping insight for large-scale reservoir development. Additionally, this paper reveals the tool's capabilities in different geosteering applications, requiring different depth of detection (DOD) ranges for landing a well, optimizing well placement in thin reservoirs, and eliminating the need for a pilot hole.

This paper discusses in detail a new 3D finite-difference (FD) method to simulate realistic and complicated formation structures in three dimensions, enabling accurate formation interpretations and inversion of reservoir geology. Solving the scattered potential boundary value problem with the 3DFD numerical algorithm simulates the EM signals in this new LWD ultradeep application, and the modeling accuracy was benchmarked alongside in-house modeling codes and 3D commercial software. To accelerate the computation in the 3D modeling, sliding window, multicore parallel cloud computing, and decoupling between model pixel grid and FD simulation grid have been implemented for practical applications. Additionally, 3D modeling is used in the inversion to provide more accurate and complex reservoir determinations.

In addition to inversion, the tool provides 3D azimuthal multispacing, multifrequency geosignal, and resistivity measurements. Using the inversions and the 3D azimuthal images of the geosignal and resistivities enable improved reservoir understanding and geosteering decisions for the three dimensions. This paper describes two field trials from relatively thin to thick reservoirs to establish great and flexible geosteering performance because of multispacing, multifrequency measurements, and a robust signal and inversion process to optimize wellbore placements in the reservoir.
Evaluating the Impact of Multilayer Discrete Fracture Network in Hydraulic Fracture Geometry and Well Performance
Authors: Pankaj Piyush
Published: October 2018

Naturally fractured shale reservoirs are characterized by a complex 3D discrete fracture network (DFN). DFN density in different stratigraphic layers imposes variability in hydraulic fracture geometry as the hydraulic fracture propagates in the laminated shale reservoirs. The study presented in this paper aims to parametrically determine the hydraulic fracture geometry and consequent well production when varying densities of DFN interact with the propagation and growth of hydraulic fractures.

A 3D multilayer DFN (MDFN) is discretized in vertical grid elements distributed in layers of the formation. This is represented in a geocellular grid model with varying DFN sets in multiple layers. A new hydraulic fracture propagation model with stacked height has been utilized to determine the interaction of the hydraulic fractures with the DFN in all different layers. The vertical variation of the DFN causes more complex fracture propagation because it accounts for the fracture crossing criterion apart from the stress profile variation in layers and the stress shadow impact. Comparison of such complex hydraulic fracture geometry with the simplistic average 2D representation of the DFN reveals the geometry difference. This is further coupled to reservoir simulation in numerical engines to determine the difference in production performance. Finite element geomechanical simulations are made to predict microseismic events, which are then compared to the acquired microseismic data to validate the hydraulic fracture geometry.

Hydraulic fracture geometry was found to differ when an MDFN approach was taken as compared to simplistic single-layer DFN (SDFN) interaction. Production performance of the fracture geometry obtained by considering an MDFN was therefore more realistic. The simulated microseismic data also exhibited a much better match to the acquired microseismic data when an MDFN was used for modeling. Visual analytics tools for comparison of observed microseismic event distribution with predicted microseismic data in the model show errors ranging from 16% to 24% for different view representations. As a conclusion of this study, it was evident that wherever applicable, an MDFN approach should be used to determine the well completion performance. However, there is some scope for improving the modeling of hydraulic fracture interaction with natural fractures by incorporating the dip angle of the MDFN for computing the crossing criteria.

This study represents the first time a more-robust modeling of the interaction of hydraulic fractures with a 3D MDFN was achieved using complex fracture models to determine the impact on productivity. Finite-element-computed microseismic data allowed further validation. Operators can use the approach described in this study to predict their well performance more accurately in complex fracture reservoirs.
A Hybrid Data-Driven and Knowledge-Driven Methodology for Estimating the Effect of Completion Parameters on the Cumulative Production of Horizontal Wells
Authors: Guevara Jorge , Zadrozny Bianca , Buoro Alvaro , Lu Ligang , Tolle John , Limbeck Jan , Wu Mingqi , Hohl Defletf
Published: October 2018

We present a new methodology for modeling the cumulative oil and gas production of horizontal wells in a shale play given two types of well completion parameters: lateral length and proppant intensity, we also consider the location of the wells and the shut-in days of wells. We show experimental results evaluating the predictive accuracy of this methodology on hold-out data and compare it to standard data-driven estimation procedures. Our approach is based on the use of Generalized Additive Models (GAMs). The main advantage of using GAMs is that we can easily obtain effect plots that allow us to quantify the effect of each completion parameter and the location of the well on the production. Furthermore, it is possible to explicitly model the interaction between variables and impose shape constraints based on physical knowledge. We have implemented and tested this methodology in R and compared its predictive accuracy against a variety of standard data-driven modeling procedures available in the Caret package, using leave-one-out cross validation. We present experimental results using data from a shale play with 152 horizontal wells that have cumulative production for more than 12 months. Our experiments show that using GAMs in most cases leads to better predictive accuracy than the standard data-driven estimation procedures available in Caret, possibly because they allow us to explicitly model the interaction between input variables that are known to be are physically related and to impose shape constraints based on known physical relationships between input variables and target variables. We conclude that it is possible to accurately estimate the effect of the completion parameters on the cumulative production when we ensure that the models obey physical constraints, i.e., that the cumulative production is a monotonic increasing function of lateral length and of proppant intensity. We also obtain effect plots showing the "sweet-spot" effect, i.e., the relationship between the location (x, y) in the field and the cumulative production. The novelty of this hybrid data-driven and knowledge-driven methodology is to allow the quantification of the effect of completion parameters and location on well production through the combination, in a principled way, of data available from existing wells with prior/expert knowledge regarding known physical constraints.
Physics-Based Fluid Flow Modeling of Liquids-Rich Shale Reservoirs Using a 3D 3-Phase Multi-Porosity Numerical Simulation Model
Authors: Lopez Jimenez Bruno A. , Aguilera Roberto
Published: October 2018

Production from liquids-rich shale reservoirs in the United States and Canada has increased significantly during the past few years. However, a rigorous understanding of shale rocks and fluid flow through them is still limited and remains a challenge. Thus, the objective of this research is developing a 3D physics- based model for simulating fluid flow through these types of multi-porosity rocks. This is important given the recent spread of these types of reservoirs throughout the world.

Simulation of liquids-rich shale reservoirs is carried out with the construction of an original fully- implicit 3D multi-phase semi-compositional finite difference numerical formulation, which uses a multiple porosity approach as well as diffusion from solid kerogen. The multi-porosity system includes (1) adsorbed porosity, (2) organic porosity, (3) inorganic porosity, (4) natural fracture porosity, and (5) hydraulic fracture porosity. The numerical model is developed with capabilities to handle dissolved gas in the solid part of the organic matter, adsorption/desorption from the organic pore walls, viscous and non- Darcy flow mechanisms (slip flow and Knudsen diffusion), and stress-dependent properties of natural and hydraulic fractures.

Examples of simulated results are presented as cross-plots of pressure, production rates and cumulative production vs. time. These plots are utilized to show the contributions of free gas, adsorbed gas and dissolved gas on fluid production from liquids-rich shale reservoirs. Results indicate that both desorption and gas diffusion positively affect shales' performance. Simulation results demonstrate that not taking into account desorption and diffusion from solid kerogen leads to underestimating production from liquids-rich shale reservoirs. Furthermore, the simulation study shows that long periods of time are required for the effects of these two mechanisms to be manifested. This helps to explain why shales have been produced over long periods of time (several decades) like in the case of Devonian wells located in the Appalachian basin.

The type of 3D simulation model for multi-porosity liquids-rich shale reservoirs developed in this paper is not currently available in the literature. The approach implemented in this work provides a novel and important foundation for simulating complex shale reservoirs.
Application of Artificial Intelligence for Mechanistic Modeling and Probabilistic Forecasting of Hybrid Low Salinity Chemical Flooding
Authors: Dang Cuong , Nghiem Long , Fedutenko Eugene , Gorucu Emre , Yang Chaodong , Mirzabozorg Arash
Published: October 2018

After nearly thirty years of research and development, it is now widely agreed that Low Salinity Waterflooding (LSW) provides better oil recovery than High Salinity Waterflooding (HSW). Past studies also showed that there are significant advantages in combining LSW with other conventional EOR methods such as chemical flooding (polymer flooding and surfactant flooding) or miscible gas flooding to benefit from their synergies and to achieve higher oil recovery factor and project profit. This paper presents a study of Hybrid Low Salinity Chemical Flooding as a novel EOR approach with: (1) development of hybrid EOR concept from past decades; (2) implementation of an efficient modeling approach utilizing artificial intelligent technology for mechanistic modeling of these complex EOR processes; (3) systematic validation with laboratory data; and (4) uncertainty evaluation of LSW process at field scale.

The phase behavior of an oil-water-microemulsion system was modeled without the need of modeling type III microemulsion explicitly. The approach has been successfully applied to model both conventional Alkaline-Surfactant-Polymer (ASP) flooding and emerging EOR processes (LSW, Alkaline-CoSolvent-Polymer, and Low-Tension-Gas Flooding). The new development allows the mechanistic modeling of the benefits of combining LSW and chemical EOR. One of the main challenges for mechanistic modeling of these hybrid recovery processes is that several factors, e.g. polymer, surfactant, and salinity, can change the relative permeability simultaneously. To overcome this problem, Multilayer Neural Network (ML-NN) technique was applied to perform N-dimensional interpolation of relative permeability. The model was validated with coreflooding data and the effectiveness of hybrid processes were compared with conventional recovery methods.

The proposed model showed good agreements with different coreflooding experiments including HSW, LSW, and Low Salinity Surfactant flooding (LSS). This model efficiently captures the complex geochemistry, wettability alteration, microemulsion phase behavior, and the synergies occurring in these hybrid processes. Results indicated that LSS is an economically attractive hybrid EOR process since it increases the ultimate recovery factor compared to the conventional approaches and reduces surfactant retention. Bayesian workflow using ML-NN algorithm is efficient to capture the uncertainties in history matching and production forecasting of LSW.
As-Received Core Electrical Properties Tests for Determining Formation Factor FF and Resistivity Index RI
Authors: Newsham Kent , Hanna Ray , Lee Robert , Whitney Craig , Chemali Roland
Published: October 2018

We introduce a new core analysis workflow for determining Resistivity Index (RI), Formation Factor (FF), and other petrophysical properties, directly from an "as-received" (AR) set of core samples. Unlike common practices that require lengthy core cleaning and wettability restoration, the new workflow does not introduce external liquids or alter the wettability of the matrix. The new workflow starts with AR cores in the laboratory. Initial porosity and water saturation (Sw) are measured using nuclear magnetic resonance (NMR). We measure formation water resistivity (Rw) from a patented method based on resistivity dispersion. A two-electrode system provides the bulk resistivity (Rt) measurement. Sample de-saturation is by centrifuge at two drainage pressures. Sw and Rt measurement occurs at each de-saturation state. Sw measurement at each subsequent de-saturation step is by the gravimetric method. Regression analysis of the Rt and Sw data series yields Ro, the resistivity that would be expected for a 100% water-saturated sample, the Formation Factor (FF), the Resistivity Index (RI) and the Archie parameters of ‘m’ and ‘n’.

With the new workflow, cleaning, drying, and re-saturating the sample are no longer required. The risk of altering the initial wetting state of the sample is minimal. Another advantage is the reduction of lab analysis time from weeks to days. This is particularly valuable since FF and RI play an essential role in estimating hydrocarbon in place using Archie’s equation, and in providing insight into partial oil-wetting conditions.

Samples used in the method are from the Avalon and Wolfcamp formations. The method is also applicable to permeable, conventional rocks. The best estimation of Ro is from the paired Sw and Rt results measured at the AR state and after the first de-saturation step. As in the conventional method of measuring electric properties, a series of cross-plots provide a graphic solution for ‘m’ and ‘n’. A cross-plot of FF and porosity provides a graphical solution of the porosity exponent, ‘m’. A cross-plot of Sw and RI is the source for the solution of the saturation exponent, ‘n’. These graphic results compare well to results using a numerical solution. Finally, using the electric properties within the Archie equation, log based Sw values were found to be consistent with the measured Sw from core extraction.
CO2/Water Foams Stabilized with Cationic or Zwitterionic Surfactants at Temperatures up to 120 °C in High Salinity Brine
Authors: Da Chang , Elhag Armo , Jian Guoqing , Zhang Leilei , Alzobaidi Shehab , Zhang Xuan , Al Sumaiti Ali , Biswal Sibani , Hirasaki George , Johnston Keith
Published: October 2018

Stabilization of CO2 in water (C/W) foams with surfactants at high temperatures and high salinities is challenging, due to limited solubility of surfactants in aqueous phase, foamability and thermal stability. The apparent viscosities of C/W foams has been raised to up to 35 cP with viscoelastic aqueous phases formed with a diamine surfactant, C16-18N(CH3)C3N(CH3)2 (Duomeen TTM), or a zwitterionic surfactant, cetyl betaine, at 120 °C in 22% total-dissolved-solids (TDS) brine. Duomeen TTM is switchable from the nonionic (unprotonated amine) state, where it is soluble in CO2, to the cationic (protonated amine) state in an aqueous phase under pH ~6. Therefore, it may be injected in either the aqueous phase or the CO2 phase. The formation of viscoelastic phases with both surfactants lowers the minimum pressure gradient (MPG), and strengthens the lamella against drainage and Ostwald ripening by making the external aqueous phase more viscous, leading to stable foam even at very high foam quality. Both surfactants were shown to have excellent thermal stability and to form unstable emulsions when mixed with oil (dodecane). The core flood results showed that strong foam could be easily generated with both surfactants at a superficial velocity of 4 ft/day. The oil/water (O/W) partition coefficient of Duomeen TTM was very sensitive to pH, while that of cetyl betaine was constant over a wide range of pH. The ability to stabilize C/W foams at high temperature and salinity conditions with a single thermally stable surfactant is of great benefit to a wide range of applications including EOR, CO2 sequestration and hydraulic fracturing.
Consecutive Tracer Tests and Pressure Data Reveal Changes in Flow Regime Leading to Incremental Oil Production, Polymer Pilot, 8 TH Reservoir, Austria
Authors: Lüftenegger Markus , Clemens Torsten , Chiotoroiu Maria-Magdalena , Puls Christoph , Huseby Olaf
Published: October 2018

Polymer Flooding has been shown to increase oil production. The reason for increasing oil production is acceleration along flow paths but also flow diversion from higher permeability to lower permeability areas. Tracer tests performed in the 8 TH Reservoir in Austria prior, during and after polymer flooding show that the flow system dramatically changed. The connected volumes from injector to producer as well as the flow heterogeneity were influenced and substantial incremental oil produced. A number of tracer tests were performed in the pilot area of a polymer flood at various times. In addition, pressure data and polymer rheology was analyzed.

The tracer results were used to calculate flow pattern, dynamic Lorentz coefficient and connected volumes. Pressure data were used in combination with geomechanical modelling to investigate the injection regime (matrix or fractures). The interpretation of the data was combined with the determination of incremental oil production based on simulation. The tracer tests reveal the dramatic changes in flow patterns, connected volume changes by more than a factor of three occurred and the Lorentz coefficient indicating the heterogeneity of flow changed by more than a factor of two. The injection regime changed from injection under matrix conditions prior to polymer flooding to injection under fracturing conditions during polymer injection and back to injection in matrix conditions during chase water injection.

The reason for the changes in injection conditions is the near-wellbore viscoelastic rheology of the High Molecular Weight Polymers which were used. The growth of fractures leads to additional alteration of flow paths. The design of polymer flooding needs to take into account that flow paths are not only changed due to the reduction in water relative permeability resulting from polymer adsorbing to the rock and the increased viscosity of the injected fluid but also owing to changes in injection regime. The changes in injection regime might lead to early breakthrough of chase water as it might not flow along the same paths as the polymer solution.
Contribution of Oil and Gas Production in The US to The Climate Change
Authors: Lancon Olivier , Hascakir Berna
Published: October 2018

The oil and gas industry has often been blamed for its major contribution to greenhouse gas releases and designated as a target to knock down by media, activists, and environmentalists. It is true to say that without Oil and Gas Industry, anthropogenic emissions of CO2 and CH4 would be much lower. Similarly, it is also true to state that without this industry and petroleum products, our life standards would be much different than the current standards. One should not confuse an activity which generates greenhouse gases, and the effect of product consumption. Evaluating the real routine emissions of the oil and gas industry on the same mode than every other industry is possible and constitutes the objective of this work. As a preliminary result, however, data coming from the Environmental Protection Agency (EPA) clearly highlight that oil and gas production accounts for at least less than 10% of the greenhouse gas emissions from the energy sector in the United States. To more precisely evaluate these emissions, this study relied on environmental impact reports in terms of greenhouse gas emissions, which are available for every production site in the U.S, as well as the oil and gas consumption in the US over the year 2015. Emissions happen during three different stages of the hydrocarbon production; extraction, flaring and venting, and fugitive emissions. The importance of each stage in terms of emissions is extremely variable, depending on the quality of the oil, the field location, and the existence of an outlet for the produced gas. The greenhouse gas emissions contribution from the Oil and Gas industry is 3% for extraction, and about 0% for flaring and venting, and 0% of fugitive emissions in the US. The remaining U.S greenhouse gas emissions while processing petroleum products are due to refining at 88%, and transportation at 9%. However, these results are extremely different for Canadian oil sands, Venezuela heavy oil, Arabian light oil, or Indonesian gas condensate. Worldwide, greenhouse emission source for petroleum industry are 10% for extraction, 19% for flaring and venting, 6% of fugitive emissions, 4% of transport, and 61% of the refinery. As a result, 3.5% of greenhouse gases emitted while processing petroleum products are due to Oil and Gas industry. Based on these results, an extrapolation to the worldwide Oil and Gas production enable to assess the participation of this industry to total emissions. Results show that less than 3 % of worldwide greenhouse emissions comes actually from Oil and Gas industry.
Analysis of Chemical Compositions Injection Combined with Cyclic-Steam Stimulation
Authors: Kuvshinov Ivan , Kuvshinov Vladimir , Altunina Lyubov
Published: October 2018

The paper presents the analysis of cyclic steam stimulation (CSS) application results for producing wells on Permian-Carboniferous deposits of Usinskoye oilfield of high-viscosity oil, the Republic of Komi, Russia. The application of thermotropic chemical compositions for enhanced oil recovery combined with CSS is discussed. Data on treatment of more than 170 cyclic-stean wells for 2017, as well as statistical data on cyclic steam stimulation for 2014-2017 are given. Among the wells considered are both wells treated with steam only, and in combination with chemical compositions of two types, oil-displacing and flow-diverting. The compositions used are thermotropic, using the energy of the injected fluid to activate the necessary chemical reactions, such as gelling or the formation of an alkaline buffer system. Also, the effect of CSS for wells where this treatment is applied for the first time, with wells with multiple CSS (from two to ten cycles), is compared. Experimental curves of efficiency distribution are obtained, expressed in the increase in oil production rate after treatment, for different well groups.

The analysis of the efficiency of the CSS on a large data set was carried out, the asymmetries in the efficiency distribution of the wells were revealed, where the CSS was used for the first time. The first CSS cycle, especially when the well is put into operation from inactivity or after drilling, is most effective, the average flow rate after treatment is 24.0 tons/day, with multiple treatments the efficiency is significantly reduced, a decrease to 5.5 tons/day is observed.

The influence of chemical compositions of various functional purposes on the efficiency of cyclic steam stimulation has been studied. With repeated CSS, the use of the oil-displacing composition is efficient and reasonable, since one of the main declared functions of the composition is precisely the extra washing of the residual oil. The average yield for repeated treatments with a composition is 10.9 tons per day. The use of the gel-forming (flow-diverting) composition with the CSS reduces the water cut of the product by 30-40%, and stabilizes the average result of the treatments, both at low and high efficiencies, so that application of such a composition is undesirable in wells with a high oil production rate before the CSS, but is valid for highly watered wells.

Based on the results of the analysis, it was concluded that for the new wells, the first cycle of CSS is most effective, and the use of chemical compositions is not necessary, but for subsequent cycles, it is recommended to use chemical compositions that will provide afterwashing of residual oil and reduced water cut. For old wells, where no CSS was previously used, it is necessary to evaluate the expediency of using chemical compositions in the first cycles based on the dynamics of the well and the initial water cut.