bluuebunny/crossref_metadata_2025 huggingface dataset:
On the Prediction of Gas Solubility in Brine Solutions for Applications of CO2 Capture and Sequestration
Authors: Ratnakar Ram R. , Venkatraman Ashwin , Kalra Amrit , Dindoruk Birol
Published: October 2018

Geological storage of CO2 in deep saline aquifers has become a well-accepted method for CO2 sequestration. CO2-solubility in these brine solutions is one of the most important factors in determining the amount of CO2 sequestered in these aquifers. Since the type of salt can significantly alter the CO2-solubility in brine solutions, the impact of water chemistry on CO2 solubility is investigated in this work and results are compared against experimental observations.

The current work for predicting solubility of a gas in brine solution containing various salts is based on the extension of well-known Setschenow relation that has been commonly used for salts with monovalent ions. In this research, we extend the Setschenow approach by expressing the solubility in terms of ionic strengths and molar concentrations of each salt. The method also characterizes each component (e.g., gas, anions and cations) against the experimental measurements.

A simple methodology, developed with a theoretical framework, is presented to predict the impact of different types of salts on solubility of CO2. This approach can be extended to any type of gases or other solutes (e.g. CH4, H2S etc.) in brine solutions. In particular, The gas solubility in brines is expressed in terms of molar components and ionic strength of each salt. The expression contains unique/characteristic parameters for each component (gas, anions and cations). These parameters for anions and cations of typical formation water (present in oil/gas reservoirs) and CO2/novel solvents are obtained from literature or using regression on experimental data.Results of CO2-solubility were compared with published data in literature, demonstrating that the methodology (presented in the work) can predict the effect of water-chemistry on solubility predictions.The proposed method was tested for a novel solvent (dimethyl ether) and comparison with experimental solubility data show an excellent match between the predictions and measurements.
Improved Collaboration and Transparency of Oil & Gas Capital Projects Using a Digital Project Delivery System
Authors: Stroh Jeffrey , Naik Harit , Memi Edmund
Published: October 2018

The adoption of a digital project delivery methods utilized by the manufacturing industry can be applied to oil and gas capital projects. Benefits include: greater collaboration and transparency between an EPC and owner-operator, the use of near real-time data to facilitate and drive better project decision-making, and the ability to save resources through increased efficiencies. To better understand poor performance on capital projects, different methods must be looked at. A case study using implementation of a digital project delivery approach through Project Lifecycle Management (PLM) is compared to a legacy project delivery using disconnected tools. This new approach to project delivery shows how adapting PLM software brings together engineering data with planning information, digital action workflows, collaborative review sessions, and visualization of status using a 3D model into a new way of delivering oil and gas capital projects more efficiently. The project schedule is merged with the master deliverables register and data coding to create live project dashboards and end-to-end schedule visibility. Going beyond the technological aspects, the behavioral and organizational challenges of project execution are examined, highlighting the limitations of legacy approaches and the project benefits gains using the digital project delivery approach.

By leveraging the interconnectedness of data, the real-time insights that can be derived, and with the right project team support model, all of these factors come together to show how application of digital project delivery systems enables better project management visibility and capital project performance.
Review of Permian Completion Designs and Results
Authors: Jaripatke Omkar A. , Barman Indranil , Ndungu John G. , Schein Gary W. , Flumerfelt Raymond W. , Burnett Nikki , Bello Hector D. , Barzola Gervasio J.
Published: October 2018

One of the most significant elements in the successful development of an unconventional multi-layered horizontal shale play, such as the Permian Basin Wolfcamp and Spraberry shales, is the continuous refinement of completion design programs in order to account for the specific geological characteristics of the target formation and spatial considerations. This paper examines a number of well completions, a large percentage of which are multi-stacked, over a four-year period in the Permian Basin.

In this paper, we describe the ways in which a completion design program has been constantly refined in the development of Wolfcamp and Spraberry formations over certain areas of Midland Basin. Key performance drivers, such as regional pore pressure, rock properties and stresses, well spacing, etc. along with multidisciplinary data sets such as microseismic, tracers, bottom hole reservoir pressure, and production history are incorporated into modeling the completion designs.

Details of the workflow, analysis of results and implementation of the Permian multi-stack design optimization plan are presented. The paper includes lessons learned from early vintages to modern completions, parent/child mitigation strategies, and future ideas to further optimize the operations.

Information presented in this paper will help multi-disciplinary asset teams, consisting of engineers, geologists, analysts and managers; design a workflow for selecting appropriate design solutions for their individual shale assets.
Eagle Ford Huff-and-Puff Gas Injection Pilot: Comparison of Reservoir Simulation, Material Balance and Real Performance of the Pilot Well
Authors: Orozco Daniel , Fragoso Alfonso , Selvan Karthik , Aguilera Roberto
Published: October 2018

A comparison is made of real data from an Eagle Ford huff-and-puff (H&P) gas injection pilot with reservoir simulation and tank material balance calculations. The comparison is good and supports the conclusion that oil recovery from the Eagle Ford (and likely other shales) can be increased significantly with the use of H&P.

The study is based on the container methodology: for H&P to work, the injected gas and the insitu oil in the shale must be contained vertically and laterally following hydraulic fracturing. Containment is critical for the success of H&P. Vertical and lateral containment exist in the Eagle Ford as demonstrated previously (Fragoso et al., 2015) with the upside-down distribution of fluids: natural gas is at the bottom of the structure, condensate in the middle and oil at the top. Two different matching and forecasting approaches are used in this study: reservoir simulation and tank material balance calculations.

Results show a good history match of primary recovery and secondary recovery by H&P in the pilot well. The history match is good in the case of both reservoir simulation and tank material balance calculations. Once a match is obtained, the simulation and material balance are used to forecast secondary recovery over a period of 10 years with sustained H&P injection of dry gas. Results indicate that dry gas H&P can increase oil recovery from the Eagle Ford shale significantly. Under favorable conditions, oil recovery can be doubled and even tripled over time compared with the primary recovery. The addition of heavier ends to the H&P gas injection can increase even more oil recoveries, putting them on par with conventional reservoirs. The benefit of H&P occurs both in the case of immiscible and miscible gas injection. The H&P benefits can likely be also obtained in other shale reservoirs with upside-down containers for dry gas, condensate and oil.

The novelty of the work is the combined use of reservoir simulation and tank material balance calculations to match performance of an H&P gas injection pilot in the Eagle Ford shale of Texas. The conclusion is reached that oil recoveries can be increased significantly by H&P.
Asphaltene Gradients and Connectivity Analysis in Reservoirs, Asphaltene Onset Pressure, Bitumen and Tar Mats All Treated Within a Simple, Unified Chemistry Treatment
Authors: Mullins Oliver C. , Dumont Hadrien , Forsythe Julia C. , Chen Li , Achourov Vladislov , Meyer John , Johansen Yngve Bolstad , Rinna Joachim , Winkelman Ben , Wilkinson Tim W. , di Primio Rolando , Elshahawi Hani , Canas Jesus , Betancourt Soraya S. , Pomerantz Andrew E. , Zuo Julian Y.
Published: October 2018

Asphaltenes can be dispersed in crude oils in 3 different forms; molecules, nanoaggregates (of molecules) or clusters (of nanoaggregates); these forms are codified in the Yen-Mullins model and relate to the extent of solvency of the asphaltenes in the crude oil. Many reservoir studies are used here to show the systematic behavior of the specific asphaltene species in crude oil and the corresponding magnitude of the asphaltene (and viscosity) gradients. In addition, the specific asphaltene species is related to the chemical origin controlling asphaltene onset pressure (AOP) and tar formation and depends on 1) the quality of the live crude oil solvent for asphaltenes and 2) the concentration of asphaltenes. Elevated quantities of solution gas of a reservoir crude oil significantly reduce the solvency of asphaltenes in crude oil. For low concentrations and/or good solvency, asphaltenes are dispersed in crude oils as molecules with small gradients (unless there are large GOR gradients). For moderate concentrations and/or moderate solubility, asphaltenes are dispersed as nanoaggregates with intermediate (gravity) gradients of asphaltenes. With large concentrations and/or poor solvency, asphaltenes are dispersed as clusters with very large gradients in reservoirs. These crude oils can also exhibit higher asphaltene onset pressures and/or phase separated bitumen or tar in the reservoir depending on the origin of asphaltene cluster formation. Secondary gas charge into oil reservoirs can yield tar and/or a high AOP. The effect of biodegradation on these factors is also discussed. The systematics presented here are helpful in understanding a variety of reservoir concerns associated with asphaltenes.
Ultra-Light Weight Proppants for Better Placement
Authors: Bestaoui-Spurr Naima , Li Chunlou
Published: October 2018

As well construction technology enables ever-longer horizontal reach, the challenge increases for proppant placement in hydraulic fracturing operations. Effectively placing conventional proppants (sand and ceramic) in extended-reach wells requires either high pump rates or high-viscosity fluids and are subject in both cases to early proppant settling and banking. Even when heavily gelled fluids are used, proppant suspensions are subject to particle settling in the presence of vibration, and/or due to fracturing fluids breaking before the fracture closes. Furthermore, the fractures are typically vertical; and in this case the proppant has a tendency to settle in the lower portion of the fractures while the upper portions close in the absence of proppant. This can lead to impairment in the geometry of the fracture and well productivity. Using proppant with much lower densities than that of conventional proppant will provide better transport. Another benefit from these ultra-lightweight proppants (ULWP) is the elimination of polymer damage with the use of low-polymer or slick water fluid systems, enabled by their extremely slow settling rates.

Since the mid-2000s, ULWP has been used in over 3000 wells to overcome placement and settling challenges. Taking advantage of low-viscosity fluids, ULWP have been used as nearly neutral buoyant proppant; thus, minimizing settling within the created fracture and leading to a better placement. In this study, the hydraulic treatment and production data of those wells treated with ULWP and offset wells were carefully reviewed. Main production metrics are calculated to evaluate the production performance.
Case Study: Apache's Approach to Societal Responsibility thru the Environmental Media Monitoring Program for the Alpine High Play
Authors: Behl Navneet , Bohm Brian , Bruton Marcus , Fleming Steven , Vance Steven
Published: October 2018

A baseline environmental media monitoring program is presented. Analytical data sets collected by third party contractors at the request of Apache Corporation are presented. The analytical data presented documents the environmental condition of groundwater, surface water, soil, and ambient air, within an area with sensitive environments supporting multiple endangered and threaten species, recently being developed as oil and natural gas exploration and early development. The area of the study is a previously undeveloped portion of the prolific oil and gas development area of the Permian Basin. The baseline environmental media monitoring program occurred over an area of approximately 78 square miles in southern Reeves County, Texas. The analytical data provides interested stakeholders a starting data set for comparison to future environmental conditions, allowing parties to assess if there are changes in the environmental media and if those changes vary from natural seasonal variations.
Deployment of Liner Systems in Extreme High Mud Weight Environments in Gas Wells
Authors: Oqaili A. H. , Alluhaydan A. S. , Ezi P. C. , Tirado A. E.
Published: October 2018

During the development phase of a gas field, the abnormal pressure in a dolomitic limestone formation demanded an extremely high mud weight to control the well. The casing design of this case-study field has entailed the installation of a 7″ × 9-5/8″ liner hanger in combination with a liner top packer followed by a tieback to surface. Due to this hole section being directly above the pay zone, it is crucial that the liner installation and the wellbore integrity are not compromised for the subsequent well completion.

The downhole pressure conditions require a drilling mud weight up to 157 pcf (~ 21 ppg), where solids content could reach as high as 49% using conventional weighing materials. For a liner deployment, this means that the high concentration of solids can cause plugging in the setting ports of conventional hydraulic liner hanger and running tool system. Additionally, the thin balance between ECDs and the formation fracture pressures in this field generated events of severe fluid loss during the liner deployment or while cementing. A liner not fully supported by cement — due to severe fluid loss during cementation — can experience ballooning, and be unable to withstand piston forces acting against the liner top packer during well completion operations. These forces can, in some cases, exceed the ratings of the liner top packer's hold-down slips, therefore allowing the packing element of the liner top packer to not set properly.

For these reasons, an optimized deployment strategy was planned and implemented to address these challenges. It included improvements to the hydraulic liner hanger and running tool system, calculations to simulate an optimal running speed of the liner, enhanced procedures for liner deployment and cementation, including revised setting procedures for the liner hanger slips, and modifications to drill pipe wiper plug design.

The objective of this paper is to detail the benefits of implementation, detailed pre-job planning, improvements for optimal drilling mud properties and modifications to the liner hanger system, and procedures that resulted in successful deployments of liners in this field. In addition, a case study will be shared as a way to institute lessons learned and best practices.
A Novel X-Ray Based High Pressure Mass Flow Rate Sensor for MPD Operations
Authors: Singhal Vivek , Ashok Pradeep , Oort Eric van , Park Paul
Published: October 2018

Managed Pressure Drilling (MPD) allows one to drill through formations with narrow pressure windows, thereby making those formations that cannot be drilled with conventional techniques accessible. It also provides the capability for early detection and safer handling of well control events. This technique requires accurate estimation of the annular pressure profile and the delta mass flow rate. These measurements can be improved through accurate density and mass flow rate measurement at the high pressure (7500 psi) input side of the well. Since no good metering technologies exist to make these measurements, the objective was to develop a high pressure density and mass flow rate sensor.

A comprehensive review of all existing flow rate and density measurement instruments suggested that an X-ray based sensor was the best option for the high pressure fluid line. Multiple experiments were conducted to determine the electrical power range (voltage and power) for the X-ray tube that would work best for mud between densities in the range of 8 to 20 ppg. Experiments were then conducted to test the accuracy and feasibility of techniques developed for density and volumetric flow rate measurement. Based on these experiments, an X-ray source and detector were identified and a sensor was designed for inline use on 4 inch pipes. Two approaches were developed to estimate density using the sensor. The first was an empirical approach where sensor gray level values were directly mapped onto mud density values though in laboratory experiments. These mappings can then be used in the field to estimate density. The second was a model-based approach that estimates density based on the Beer Lambert's law. Both these approaches were tested experimentally using drilling muds of different densities and compositions.

A mechanism that uses X-rays to determine volumetric flow rate was also designed and tested using both simulations and experiments. A real-time calibration subsystem had to be added to the sensor to preserve measurement accuracy and precision over time. Based on encouraging results from simulations and experiments, a laboratory prototype was built and is currently undergoing flow loop tests. This is the first time an X-ray mass flow rate measurement sensor has been designed to be used on high pressure lines. Preliminary findings indicate that no existing sensors used for similar applications can match the measurement accuracy and frequency that may be offered by this technology. Development of this sensor would improve the safe drilling of complex wells with narrow drilling windows.
Effect of Anisotropic Fault Permeability Alteration on Pressure Transient Behavior
Authors: Molina Oscar , Zeidouni Mehdi
Published: October 2018

Compartmentalized reservoirs are often segmented by a sealing fault acting as a barrier to pressure communication between neighboring reservoirs. However, changes in reservoir pressure, due to either fluid withdrawal or injection, can induce changes in local stresses that can lead to fault slip and associated alteration of fault permeability, which can transform the initially sealing fault into partially conductive.

This paper examines the transient pressure response to a sudden change in anisotropic fault permeability as an indicator of fault seal breakdown. Analytical solutions for pressure-transient response for a line-source, constant-rate well in a compartmentalized reservoir where fault permeability is rapidly enhanced, are presented. The fault is modeled as a linear interface between semi-infinite homogeneous and isotropic formation layers. Laplace-Fourier transform technique is used to solve the governing equations analytically. Pressure-transient solutions are presented as type curves for the scenarios of across-fault and simultaneous across-along-fault permeability enhancement. Characterization of enhanced fault transmissibility using asymptotic late-time solutions is discussed.
Seismic Lithofacies for Static Model Building and STOIIP Calculation in Bioturbated Shallow Marine Environments
Authors: Baharuddin Saira Bannu , Khair Hani Abul , Bekti Reza Amarullah , Ali Amita Mohd , Kantaatmadja Budi , Som Mohd Rapi , Sedaralit Faizal
Published: October 2018

Bioturbated zones are frequently bypassed by oil and gas operating companies during perforation due to the perception that they are non-productive. We analysed data from wells in four fields in the Sarawak Basin, Malaysia, for selected bioturbated zones. The study included thin section, probe-permeameter, petrophysical, and routine core analysis. A bioturbation index classification scheme was established to allow semi-quantitative ranking for each foot of core.

In the current study, we introduce a simulation script to predict lithofacies types at well locations based on input from bioturbation intensity algorithm (Ali et al., 2016), this script can be used for application on shallow marine field within Malaysia.

We also used post stack seismic inversion for acoustic impedance and it proved to be a key approach to enhance the ability of predicting rock properties between wells. We generated a seismic derived lithofacies which provided the best estimate of lithofacies distribution between wells even though a well derived lithofacies had higher resolution. We calculated STOIIP using input from seismic lithofacies and porosity, and the results showed more accurate estimate of hydrocarbon in place compared with statistical approaches. Thus, the current seismic lithofacies methodology can be used for static model building and STOIIP calculation in shallow marine environments.
Cellulose Nanocrystal Stabilized Emulsions for Conformance Control and Fluid Diversion in Porous Media
Authors: Pandey Aseem , Telmadarreie Ali , Trifkovic Milana , Bryant Steven
Published: October 2018

Nanoparticle stabilized emulsions have drawn increasing attention for applications in various industries including enhanced oil recovery (EOR). Unlike surfactants, nanoparticles provide long-term stability to the emulsions and significantly higher viscoelastic response. However, the flow behavior of nanoparticle stabilized emulsions in porous media has not been explored much. Cellulose Nanocrystals (CNCs) have gained attention in the past few years since they are an abundant renewable biomass-derived material. This study investigates the flow behavior and stability of oil in water emulsions stabilized by CNCs in unconsolidated porous media and the application of these emulsions in EOR and conformance control.

Confocal Microscopy coupled with Cryo-SEM enabled us to precisely characterize the emulsion microstructure and correlate it to the rheological behavior of the emulsions. The rheological measurements revealed that a strong droplet network forms within the emulsions over time. Importantly, we show that the same network forms when the emulsions occupy pore space in a granular material. Emulsions were injected through a sandpack with a porosity of 35% and average pore diameter of 54 μm. The injected emulsions were aged inside the porous media for 24 hours. Thorough experimental assessment of the collected effluent samples revealed that the emulsion was stable. The porous medium was then subjected to a gradually increasing pressure gradient of either water or oil. Gradients greatly exceeding typical near-well values (>300 psi/ft) were required to establish flow, and the resulting flow rate exhibited a pressure gradient three orders of magnitude higher than in an untreated water saturated sandpack. Interestingly, a significantly larger gradient was needed for water to flow than for oil, raising the possibility of using this class of emulsions for selective phase blocking, and perhaps as relative permeability modifiers. Moreover, emulsions stabilized with other material allowed water to flow at very small gradients, confirming that the network formation is critical for this application.

This study revealed the potential application of a naturally occurring biodegradable nanomaterial for conformance control and for curbing excessive water production where zonal isolation is difficult to achieve.
What Happens after the Onset of Liquid Loading? — An Insight from Coupled Well-Reservoir Simulation
Authors: Tang Hewei , Chai Zhi , He Youwei , Xu Boyue , Hasan A. Rashid , Killough John
Published: October 2018

Liquid loading is an inevitable production issue for mature gas fields. A varied group of phenomena after the onset of liquid loading has been observed in field, including the natural cyclical production of liquid loaded wells. Most previous modeling studies focused on predicting the onset of liquid loading. The production behaviors after the onset of liquid loading is equally important and requires strict modeling techniques to simulate dynamic interactions between wellbores and reservoirs.

In this paper, we apply a newly developed fully implicitly coupled well-reservoir simulator to systematically investigate the well behavior after the onset of liquid loading. The model honors the mass and momentum balances in both reservoir and wellbore systems, and thus allows us to analyze both wellbore and reservoir dynamics after the onset of liquid loading. The simulation results indicate that there exist a gas-water coproduction period and a zero liquid production period after the onset of liquid loading. For reservoir permeability as low as 0.1md, the liquid-loaded horizontal well might experience natural cyclical production after the onset of liquid loading, which coincides with field observations. Both uniform stimulation and multi-stage hydraulic fractures help mitigate the production phenomenon. The near-wellbore reservoir pressure build up and wellbore fluid reinjection are also evaluated. This work demonstrates the successful application of the coupled wellbore reservoir model in predicting the rich production phenomena of stimulated horizontal wells after the onset of liquid loading.
Formation Evaluation, Economic and Environmental Assessment for the Slurry Injection for Biosolids Management in the City of Houston
Authors: Panchal Yashesh , Mohamad Ibrahim , Abou-Sayed Omar , Abou-Sayed Ahmed , Bruno Mike
Published: October 2018

A strong economy, industrial base, and low cost of living have led to a significant rise in population in the Greater Houston Metropolitan area of Texas, and with it, an increase in production of sewage and biosolids wastes. In the Houston area, sewage is treated with a combination of anaerobic digestion and lime stabilization to create biosolids which are then pelletized into fertilizer, composted, landfilled, or land applied.

The Slurry Injection technique is an alternative treatment and disposal method, that can replace much of the capital costs associated with maintaining and expanding the wastewater treatment infrastructure in Houston at significantly lower capital cost. This technique utilizes the principles of Drill Cutting Injection which has been implemented in petroleum industry since mid 1980s for oil and gas waste management. A biosolids slurry injection facility of sufficient capacity to dispose of all the biosolids currently produced by the city of Houston could be installed for less than 1/10 of the nearly $526 million in capital currently budgeted by the city to expand the current system under the current rolling 5-year plan. A substantial reduction in greenhouse gases is achieved as well, by using the slurry injection technology as the Carbon Dioxide and Methane (which are prominenet greenhouse gases) produced by biosolids degradation is completely sequestered under deep geological formation and along with it the emissions produced during dewatering and transportation of biosolids is also eliminated.

The City of Los Angeles’ Terminal Island Waste Water Treatment Plant facility has deployed the slurry injection technology since 2010. It currently disposes of approximately 20% of biosolids of the city of Los Angeles.

This paper describes the economic and environmental aspects related to biosolids management and the formation evaluation carried out to inject the bioslurry in greater Houston. The study includes both the economics of the surface construction requirements as well as the science behind the subsurface strata evaluation for containment assurance. For the subsurface aspects, a geomechanical and stress analysis is performed on two different formations (the Frio and the Vicksburg). A significant confining layer is present above and below our targeted injection zones, which restrict and assure the injected waste remains contained. Also, hydraulic fracture simulation and analysis provides an assurance and the waste containment within the engineered subsurface strata/formation for permanent storage.
Measurement of Reduced Permeability at Fracture Face Due to Proppant Embedment and Depletion
Authors: Karazincir Oya , Li Yan , Zaki Karim , Williams Wade , Tan Yunhui , Wu Ruiting , Rijken Peggy , Rickards Allan
Published: October 2018

Proppant embedment at the fracture face of a hydraulically fractured formation can result in reduced hydrocarbon flow from the matrix into the fracture due to reduced pore throat size, crushing of the rock, fines generation and pore plugging within the embedment zone (i.e. at the fracture face). Conventional proppant conductivity tests can only measure conductivity losses that occur within the proppant pack due to frac gel damage and compaction, not the damage at the fracture face. Test methods that can directly measure the effect of embedment on hydrocarbon production rates from a fracture are needed. A new test method that can measure proppant embedment at the fracture face as a function of different variables such as depletion, formation UCS and permeability, proppant type and loading has been developed. The same test method can also measure the resulting changes in the fracture-face permeability and the rate of fluid flow from the matrix into the fracture as a function of depletion, coupled with conductivity measurement within the proppant pack. A numerical model was built to provide reference solutions for the initial permeability.
Aquifer Monitoring Technology for Safe Shale Oil and Gas Exploration and Extraction
Authors: Tuxen Anders , Boughrara Salman Amina , Davis John , L. Pedersen Poul , L. Byg Casper , Frederiksen Maj , A. Hansen Jacob , N. Skov Søren , T. Kjeldsen Kasper , Hone Jim , Wood Andrew , T. Craster Bernadette , Shillam Jason
Published: October 2018

Analysis of dissolved methane and volatile organic compounds (VOCs) in water is crucial in monitoring the underground water quality, specific to shale oil and gas subsurface activities. Existing methods for monitoring these analytes generally rely on manual sampling at hydrogeological boreholes followed by off-line chromatography-based laboratory analysis. These methods are labor intensive and prone to errors. In addition, they do not capture the dynamic variations, which are particularly interesting in the occurrence of methane. In this work, a new sensor-based instrumentation for in-situ detection and measurement of methane and VOCs in subsurface environments is presented. The methane detection method relies on the Non-Dispersive Infrared technology whereas VOCs are detected using the principle of photoionization detection.

It is demonstrated that the system has a relatively short response time combined with low detection limits for methane and VOCs. This makes the system suitable for monitoring aquifers in shale gas exploration sites with a fairly high temporal resolution thus giving information on dynamic variations in the methane and VOC concentrations.
Integration of Dual-Porosity Modeling with 4D Seismic and Microseismic Technology in Niobrara and Codell Formations, DJ Basin
Authors: Ning Yanrui , Kazemi Hossein , Davis Tom
Published: October 2018

This paper presents construction and validation of a reservoir model for the Niobrara and Codell Formations in Wattenberg Field of the Denver-Julesburg Basin. Characterization of Niobrara-Codell system is challenging because of the geologic complexity resulting from the presence of numerous faults. Because of extensive reservoir stimulation via multi-stage hydraulic fracturing, a dual-porosity model was adopted to represent the various reservoir complexities using data from geology, geophysics, petrophysics, well completion and production. After successful history matching two-and-half years of reservoir performance, the localized presence of high intensity macrofractures and resulting evolution of gas saturation was correlated with the time-lapse seismic and microseismic interpretations. The agreement between the evolved free gas saturation in the fracture system and the seismic anomalies and microseismic events pointed to the viability of the dual-porosity modeling as a tool for forecasting and future reservoir development, such as re-stimulation, infill drilling, and enhanced oil recovery strategies.
Application of Conventional Forecasting Methods to Waterfloods with Horizontal Wells in Heavy Oil Reservoirs
Authors: Delamaide Eric
Published: October 2018

Using horizontal wells for primary production of heavy oil reservoirs is common in Canada but it is less frequent to employ them for waterflood. As a result, very few papers have been published on this topic. Similarly, numerous publications are available on the use of conventional forecasting methods to evaluate waterflood performances, but very few if any have focused on waterfloods with horizontal wells in heavy oil reservoirs. This is what this paper proposes to do.

The production performances of over twenty horizontal wells from five Canadian heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. Conventional waterflood forecasting methods such as Arps, Yang and logarithm of Water-Oil Ratio (WOR) vs. Cumulative oil production were used and compared. However, the focus of the paper is not only the comparison of the various forecasting methods but also the evaluation of the performances of horizontal well waterfloods in these high oil viscosities.

The Arps method appears difficult to use, especially when there are strong variations in injection rates. By comparison, the Yang and the WOR vs. Cumulative production methods appear more stable. The forecast in cumulative production can vary widely between these methods. Ultimate recovery is expected to vary from a few percent OOIP to over 20%OOIP.

This paper will present the performances of several horizontal waterfloods in heavy oil reservoirs in Canada and compare several waterflood analysis methods. Very few if any paper has been published on this topic thus the information provided will be of interest to engineers who are considering using horizontal wells for waterflood as a follow-up to primary production in heavy oil reservoirs.
Managing Process Safety Risk at the Dynamic Frontline
Authors: Jones Simon , Brewer Courtney
Published: October 2018

Process safety approaches developed and implemented over the past 20-30 years have enabled us to improve the design basis of our facilities. Yet we still see major incidents occurring at a steady rate. Traditional approaches to risk management may be appropriate as a basis for design, but they are not helpful in operations management where decisions continuously take place that impacts exposure to Major Accident Hazard (MAH) risk.

A 2017 international survey1 looked into the state of process safety and risk management in the hazardous industries. 70% of survey respondents reported a gap between how process safety management is intended and the reality of operations. Only six percent of respondents indicated their companies were up-to-date on safety critical maintenance. The survey results highlighted that the real world of operations is neither simple nor static and highlighted a gap in organizations’ abilities to develop a single, shared view of the operational reality of risk.

The current trend towards digitalization of the industry offers companies an opportunity for a clearer understanding of risk to reduce incidents and enhance the journey towards sustainable production and Operational Excellence. So-called "big data" and "edge data" techniques applied to the streams of data arising from modern facilities holds out the promise of a process safety early warning system that looks at potential signals and trends in facility operations data to make MAH risk exposure visible, prominent and available in real-time.

A new category of Operational Risk Management (ORM) software tools is emerging which seek to deliver on this promise. This paper shares the approaches adopted by two major international oil industry operators who are leveraging a new approach to process safety and operational risk management to achieve safer, more sustainable operations.
A Novel Re-Crosslinkable Preformed Particle Gel for Conformance Control in Extreme Heterogeneous Reservoirs
Authors: Pu Jingyang , Bai Baojun , Alhuraishawy Ali , Schuman Thomas , Chen Yashu , Sun Xindi
Published: October 2018

Preformed particle gels (PPG) have been successfully applied to control conformance for mature oilfields due to its advantages over conventional in-situ gels. However, field applications have demonstrated that current particle gels cannot efficiently plug opening fractures, fractures-like channels, or conduits which exist in many mature oilfields. The objective of this study is to systematically evaluate a new re-crosslinkable preformed particle gel (RPPG) product which can be used to efficiently control the conformance for the abnormal features. The novel particle gels can re-crosslink to form a rubber-like bulky material in the large opening features after placement to significantly enhance the plugging efficiency. We systematically evaluated the effect of temperature, brine concentration and RPPG swelling ratio on the re-crosslinking time, the gel strength after crosslinking, and their thermos-stability. Core flooding tests were run to test whether RPPG can significantly improve the fracture plugging efficiency comparing to a traditional PPG which cannot re-crosslink after pumping. The RPPG can be customized for the mature reservoirs with the temperature from 23 to 80°C with controllable size from tens of nanometer to a few millimeters. The RPPG swelling ratio can be controlled from 5 to 40 times. Its re-crosslinking time can be controlled from 2 to 80 h, depending on absorbed water amount, brine concentration, and temperature. The gel elastic modulus after re-crosslinking can achieve from 300 to 10,800 Pa, depending on swelling ratio. Core flooding tests showed that the breakthrough pressure of the re-crosslinked RPPG can reach up to 300 psi/ft for the fracture with the width of 5 cm and 0.2 cm aperture, which is more than 5 times higher than traditional PPGs. In addition, the plugging efficiency of the RPPG is 20 times higher than 40 K.
The Impact of Fracture Effectiveness on the Economics of Haynesville Resource Development - A Case History
Authors: Shelley Robert , Davidson Brian , Shah Koras , Sheludko Stan , Mohammadnejad Amir
Published: October 2018

Evaluating the performance of relatively deep Haynesville completions indicate that well and project hydrocarbon recovery can be negatively impacted by ineffective hydraulic frac design. Understanding the potential causes of these effects opens the door to strategies which can deliver better fracture effectiveness with corresponding increases in production and improved project economics. The subject of this paper are results from a detailed evaluation of a Desoto Parish well. This evaluation included calibration of a frac model by treatment pressure matching, use of a numeric reservoir simulator for multi-phase production history matching and comparing the fracture characteristics estimated. Also changes in conditions within the fracture over time as the wells are produced are taken into account. These evaluations concluded that completion, frac design, operational and production issues - individually or collectively - meaningfully influence the production and economics of multi-stage horizontal completions. The bottom line: Well recovery can be improved considerably with more effective frac designs that generate and/or sustain a larger contributing fracture area.

The findings show that reservoir characteristics, completion, frac design and production practices are the primary drivers of Haynesville well production. In addition, the results indicate that the hydraulic fractures created are not very efficient, in other words large portions of the propped fracture area do not contribute to well performance. This inefficiency is primarily due to conductivity limitations which can be attributed to a variety of issues including frac design, loss of proppant permeability due to stress, pinch points in the proppant bed, capillary effects, fluid retention, embedment, etc. Inefficient fractures will require more wells to be drilled in closer proximity to achieve optimum primary production. In addition the closer well spacing required in combination with high proppant intensity and large treatment volumes will increase the likeliness of adverse child to parent well interaction.
Application of Superposition Principle to Variable Rate/Pressure Production Analysis in Unconventional Gas Reservoirs
Authors: Zhang Miao , Ayala Luis F.
Published: October 2018

Application of superposition principle to non-linear gas governing equations has been an elusive goal in early-transient production data analysis and has been so far limited to the use of empirical and approximate methods best applicable to boundary-dominated flow conditions. This paper presents a novel and rigorous semi-analytical model that is applicable for the analysis of production data from multi-fractured horizontal gas wells (MFHWs) producing under early-transient variable rate/pressure production conditions. Nonlinear, pressure-dependent hydraulic diffusivity retained in pseudo-pressure-based gas diffusivity equation is straightforwardly and rigorously captured without approximation. The resulting formulation of superposition applied in nonlinear gas system is written in terms of the classical solution for linear PDE plus an analytical adjustment factor that quantifies the nonlinearity of the system. Numerical examples are presented to test the validity and showcase the capabilities of proposed approach. Comparisons against available empirical and approximate models are also provided for these cases.
Challenges and Lessons Learned During Completion of Intelligent Multilateral Wells in Minagish Field, West Kuwait
Authors: Arackakudiyil Suresh Zac , Kumar Ajit , Rondon Leonque , Pingle Darshan , Al-Hindi Khaled , Boushahri Mohammed
Published: October 2018

Multilateral intelligent wells have been proven effective by both extending reservoir contact and providing proactive reservoir management. This paper highlights the lessons learned and critical well construction and completion steps that improve the efficiency of intelligent multilateral well drilling and completions operations. The case study outlines the successful completion of the third multilateral intelligent well in the Minagish field of West Kuwait.

The intelligent level 4 multilateral well was designed and drilled successfully. The sidetrack was performed using a specialized latch coupling that allowed for multilateral window cutting, orienting, and re-entry. The latch coupling was run in hole with the main bore casing, and a key orienting tool was used to confirm its orientation. Once the main bore was complete, a window was cut using a dedicated milling machine. Thereafter, a drilling whipstock was run with a window mill and watermelon mill to allow access to the lateral. This was followed by drilling the lateral section and running and cementing the liner. After the lateral section was drilled to the planned depth and cleaned out, the whipstock was retrieved. The intelligent completion installation consisted of a lubricator valve, two downhole permanent gauges, and two variable choke interval control valves.

The presence of surface-controlled, variable choke valves to control inflow from both the main bore and the lateral provides the capability to effectively manage the reservoir and production over the life of the well. This, in turn, prolongs the field life, thus improving overall economic performance and field economics. The case study well is the third multilateral intelligent well installed in Kuwait, and many recommended practices were implemented that allowed for improved efficiency and safety of the operation. Maintaining a clean well was emphasized as a top priority throughout the well construction process. The cement curing time was increased and the completion string was reviewed and redesigned.

This paper discusses the lessons learned and improvements made during installation of the third multilateral intelligent well. The steps performed during this operation have become the recommended practices for all upcoming intelligent multilateral well operations in Kuwait.
Small Field Rejuvenation: Challenges, Lessons Learnt & Redevelopment Concept
Authors: Kueh Jing Zhi , M Dimyati Umar Islam , Wan Mat Syarifah Suliza , Michael Kennedy Macvirick , M Fadhil M Imran , Dolah Khairul Arifin
Published: October 2018

Field D is located in offshore Sarawak, Malaysia. It was discovered in 1980s, and achieved first oil in 2012. Field D is categorized as small field, due to small reserves. In order to minimize development cost, Field D development utilized refurbished platform, tied back to Field A Complex, which act as central gathering facilities for nearby fields' production. Post drilling, Field D oil production was stabilized at around 1800 barrels of oil per day (bopd). Original field life was expected to be eight (8) years, as per original PSC expiry in 2021.

In 2014, Field D PSC was extended to 2034. With the new PSC, a team had been established to study Field D potential with the objective to extend Field D life to the new PSC expiry. In order to de-risk Field D redevelopment, the team reviewed existing wells drilled in Field D, and conducted production enhancement to increase Field D production before infill drilling commenced. The team had overcome various surface and subsurface constraints in redeveloping this small field: limited facilities, production capacity limit, compartmentalized reservoir, and fluid type & fluid contact.

Field D infill drilling campaign in 2017 yielded positive results, and field production post drilling had been sustaining at 6000 bopd since. This paper chronicles Field D journey, from initial development to field redevelopment. It will benefit operators who are looking to redevelop their small field and maximize field recovery.