bluuebunny/crossref_metadata_2025 huggingface dataset:
The Use of Low-Cost Graphite Nanomaterials to Enhance Zonal Isolation in Oil and Gas Wells
Authors: Peyvandi A. , Taleghani A. Dahi , Soroushian P. , Cammarata Ryan
Published: October 2017

One of the key challenges encountered in cementing the casing in oil and gas wells is the failure of the cement sheaths due to low tensile strength and toughness resistance of the cement sheath. To enhance the mechanical and durability characteristics of cement sheaths, low-cost graphite nanoplatelet (GnP) employed as a nano-scale reinforcement. GnP offers many of the highly desired mechanical, physical, geometric and stability characteristics of carbon nanotubes (CNTs) at substantially reduced cost. Experimental studies were implemented to evaluate the complementary effects of low-cost graphite nanomaterials in oil and gas well cement sheaths. Experimental results highlighted the balanced gains in diverse engineering properties of cement slurry by introduction of GnP. As a nano-scale reinforcement system, GnPs were found to significantly control the crack propagation and improvement in mechanical attributes of Zonal Isolation. The planar geometry of GnPs makes them to be effective in improvement of durability characteristics of cementitious paste.
Spatial and Temporal Relationships between Produced Gas and Water in Marcellus through Data Mining Analysis
Authors: Zhou Q. , Wang J. Y. , Xiao Y. , Kleit A.
Published: October 2017

The relationship between produced gas and flowback/produced water is important for evaluating shale gas well performance; however, it is not fully understood yet due to complex flow mechanisms and interactions / feedback among various geoscience and engineering controls. Further investigation would provide valuable insight to adjust development plans to achieve optimal well/regional economic production.

In this study, an auto-updated nonlinear model method was applied to evaluate the relationship between water and gas in different spatial and temporal domains and to understand the micro-scale flow mechanisms from macro-scale data. Fracture-fluid flowback data in the dataset are water produced within one month, following a fracture treatment (exclusive of well shut-in time), and the produced water were 1 to 3 years. 114 wells from the Marcellus Formation in northwestern West Virginia were selected to investigate the relationship between fracture-fluid flowback and one month gas production in different spatial domains (wet and dry gas regions). 67 Marcellus wells in Lycoming County, Pennsylvania were selected to study the relationship between produced water and gas production across different time periods ranging from one to three years. The results indicate that the relationship between gas and fracture-fluid flowback in the wet gas region is positive while negative in the dry gas region. WGR (water gas ratio) is high (>9 bbl/mmcf) during the 1st-year which indicated water be carried out through displacement and leveled off at 3 bbl/mmcf after the 1st-year, indicating evaporation is the primary mechanism for water production. This study analyzed the relationship between gas and water production under different geological conditions and time periods and offers new insights on gas and fracture-fluid/produced water flow mechanisms in shale gas reservoirs.
Post-Combustion CO2 EOR Development in a Mature Oil Field: Model Calibration Using a Hierarchical Approach
Authors: Olalotiti-Lawal Feyi , Onishi Tsubasa , Kim Hyunmin , Datta-Gupta Akhil , Fujita Yusuke , Hagiwara Kenji
Published: October 2017

We present a simulation study of a mature reservoir for CO2Enhanced Oil Recovery (EOR)development. This project is currently recognized as the world's largest project utilizing post-combustion CO2 from power generation flue gases. With a fluvial formation geology and sharp hydraulic conductivity contrasts, this is a challenging and novel application of CO2 EOR. The objective of this study is to obtain a reliable predictive reservoir model by integrating multi-decadal production data at different temporal resolutions into the available geologic model. This will be useful for understandingflow units, heterogeneity features and their impact on subsurface flow mechanisms to guide the optimization of the injection scheme and maximize CO2 sweep and oil recovery from the reservoir.

Our strategy consists of a hierarchical approach for geologic model calibration incorporating available pressure and multiphase production data. The model calibration is carried out using regional multipliers whereby the regions are defined using a novel Adjacency Based Transform (ABT) accounting for the underlying geologic heterogeneity. To start with, the Genetic Algorithm (GA) is used to match 70-year pressure and cumulative production by adjusting pore volume and aquifer strength. Water injection data for reservoir pressurization prior to CO2 injection is then integrated into the model to calibrate the formation permeability. The fine-scale permeability distribution consisting of over 7 million cells is reparametrized using a set of linear basis functions defined by a spectral decomposition of the grid connectivity matrix (grid Laplacian). The parameterizationrepresents the permeability distributionusing a few basis function coefficients which are then updated during history matching. This leads to an efficient and robust workflow for field scale history matching.

The history matched model provided important information about reservoir volumes, flow zones and aquifer support that led to additional insight to the prior geological and simulation studies. The history matched field-scale model is used to define and initialize a detailed fine-scale model for a CO2 pilot area which will be utilized for studying the impact of fine-scale heterogeneity on CO2 sweepand oil recovery. The uniqueness of this work is the application of a novel geologic model parameterization and history matching workflow formodeling of a mature oil field with decades of production history and which is currently being developed with CO2 EOR.
Effect of Fluid Type and Multi-Phase Flow on Sand Production in Oil and Gas Wells
Authors: Wang Haotian , Gala Deepen P. , Sharma Mukul M.
Published: October 2017

It has been shown in controlled laboratory experiments and some field studies that the onset of sand production in gas wells differs from that in oil wells. Results from a general 3-D sand production model are presented to explain the differences in the onset of sanding and sand production volume for different fluids and under different flow and in-situ stress conditions. The sand production model accounts for multi-phase fluid flow and is fully coupled with an elasto-plastic geomechanical model. Sanding criteria considers both mechanical failure and sand erosion by fluid flow. Non-Darcy flow is implemented to account for the high flow rates. The drag forces on the sand grains are computed based on the in-situ Reynolds number. Both the intact rock strength and the residual rock strength depend on water saturation. Water evaporation (drying) due to gas flow is modeled using phase equilibrium calculations.

The onset of sand production is compared for different fluid types (oil and gas). Model results are shown to be consistent with experimental observations reported in the literature. For example, the onset of sanding is observed at higher compressive stresses for gas wells as compared to oil wells. Theprimary mechanism for this is for the first time shown to be sand strengthening induced by evaporation of water. This effect is not observed in oil wells. The sand production rate when non-Darcy effectsareconsidered is lower than for Darcy flow. The reason for this is the lower fluid velocity (for the same drawdown) and consequently smaller drag forces on the failed sand grains. The effect of water breakthrough and water cut on sand production is studied from both mechanical and erosional perspectives. The model is shown to be capable of accurately predicting the onset of sanding and sand production induced by multi-phase and compressible fluid flows, helping us to predict sanding issues in both oil and gas wells.
Employing Effective Water Treatment in West Texas to Mitigate Surface Equipment Failures
Authors: Kakadjian Sarkis , Solomon Marvin , Nwachukwu Raymond
Published: October 2017

Effective bacterial control is a key component of a successful fracturing stimulation. Currently water sources can have extremely high levels of aerobic and anaerobic bacteria that can lead to chemical degradation, microbial induced corrosion (MIC) and souring of wells due hydrogen sulfide generation. Oxidative biocides are widely used per rapid kinetics of disinfection with the capability to provide good control of bacteria loadings with short residual lifetimes.

This paper reviews steps taken to mitigate failure in fluid cylinders and flow iron surfaces that come in contact with the fluids, causing them to degrade much quicker than the normal expected life when used oxidative biocides. Premature failures of fluid ends and iron missiles are capital intensive for most hydraulic fracturing companies in the current oil and gas market. In the duration of 2 months in summer 2016, there was an unsustainable increase in maintenance costs by an estimated USD 4 million for two fracturing fleets. MIC and overtreatment of water with chlorine dioxide have been implicated in this premature failure of iron surfaces.

The water treatment process was implemented in the field in summer 2016. The mitigation process involves pretreating produced water with chlorine dioxide with no residual, which is then complemented with conventional biocides and combos for longer term bacterial control at the start of each job. Water samples of the circulating fluids are taken every 2 hours to get the relative light unit (RLU), which determines the proper timeframe for retreating the water on location. RLU values were also correlated to typical sulfur-reducing bacteria (SRB) and acid-producing bacteria (APB) levels in West Texas.

The water treatment process, with continuous monitoring, implemented over a 3-month period dramatically increased the life of stainless steel fluid ends and missiles from the 300 pumping hours and 5 months respectively. Further analysis of the effectiveness of the treatment is conducted later when the equipment is retired.
Development of a Smart Fracturing Fluid for Tight and Unconventional Reservoirs
Authors: Mohammed Marwan N. , Mahmoud Mohamed , Elkatatny Salaheldin
Published: October 2017

Massive hydraulic fracturing is the only method to have economic production from unconventional resources (i.e. tight sandstone and shale gas reservoirs, etc.). Tight permeability reservoirs represent around 60% of global unconventional resources, they have large quantities of hydrocarbon, and with their impaired permeabilities, hydraulic fracturing is the most promising technique dealing with those types of reservoirs. A typical fracturing fluid usually consists of a cross-linked gel system, buffer, clay and gel stabilizers, biocide, and a breaker among many other constituents, all to prevent damage resulting from such operations, or better yet, enhancing the formation beyond the aim of a fracturing operation.

This paper introduces a new zero leak-off, smart fracturing fluid system for tight formations and conventional resources as well. The fluid system consists of GLDA chelating agent that has the abilities of a cross-linker, breaker, biocide, clay stabilizer, replacing those constituents in one simple fluid, GLDA is also a low IFT fluid which will reduce the IFT eliminating the water blockage problems due to the capillarity effect in tight reservoirs. It is also stable in high temperature reservoirs (up to 300°F), environmentally friendly and readily biodegradable. The effect of temperature, pH, shear rate, polymer concentration and GLDA concentration on the rheological properties of the new fluid system has been studied, as well as the thickening-breaking time and efficiency, thermal stability of the developed fluid system.

The new fracturing fluid formulation can withstand up to 200°F of formation temperature and stable for about 6 hours under high shearing rates (511s−1), with polymer concentration ranging from 20 to 70 pptg with the optimum being 45 pptg at pH 12, the viscosity building and breaking time can be controlled by the concentrations of the constituents.

Coreflooding experiments were conducted using Scioto and Berea sandstone cores to evaluate the effect of the developed fluid on the core permeability and to investigate the zero leak-off property. The flooding experiments were in conformance with the rheological properties of the developed fluid regarding the thickening and breaking time as well as yielding high return permeability (85-89%).
Mapping the Natural Fracture Network in Marcellus Shale using Artificial
Authors: Mohaghegh S. D.
Published: October 2017

Contribution of Natural Fracture Network (NFN) to the productivity of shale wells is a well-established fact. So much so that it is widely believed throughout the industry that all other things being equal, the presence and the extent of Natural Fracture Network in shale determines the productivity of a shale well. While deterministic mapping of the NFN in shale through direct measurements is not an option, stochastic techniques are used to generate NFN to be used in numerical simulation. Among tools used to provide some indication of NFN in shale are wellbore image logs and seismic surveys. However, limitations of these tools for this purpose is well documented. In this paper, we present an alternative technique that makes use of a large number of field measurements and incorporates artificial intelligence in order to generate NFN map in shale.

In this technique Artificial intelligence, infers the presence and the extent of the NFN from well productivity. Parameters that impact the productivity of shale wells are: well construction … trajectory, reservoir characteristics, completion, stimulation/hydraulic fracturing, and operational conditions (wellhead pressure, choke size). Natural Fracture Network falls under the category of reservoir characteristics. In this approach Artificial Intelligence uses 12 measured parameters representing the volume of fluid available for production and operational conditions as well as completion and hydraulic fracturing practices to infer the presence and the extent of NFN.

These field measurements are analyzed on a well by well basis to generate a dimensionless score for the presence and the intensity of the NFN that are then mapped throughout the reservoir using geo-statistics. Through two case studies, we demonstrate that the discrepancies in correlation between reservoir, completion and frac job parameters and the well productivity can be explained through the presence and the extent of the Natural Fracture Network.

The results of this process is (a) a distribution map of the presence and the extent of the Natural Fracture Network throughout the reservoir and (b) a large number of examples with detail comparisons between wells that justify the generated map.
A Comprehensive Evaluation of Alkaline Surfactant Polymer Flooding and Hybrid Process for Enhanced Oil Recovery
Authors: Dang Cuong , Nghiem Long , Nguyen Ngoc , Chen Zhangxin , Yang Chaodong , Bae Wisup
Published: October 2017

This paper presents recent advances in the subject of modeling and optimization of ASP (Alkaline, Surfactant and Polymer) flooding with: (1) a critical review of the state-of-the-art development of ASP flooding; (2) an efficient and accurate novel approach for ASP modeling for robust simulation of chemical processes in conjunction with oil, gas, and water flash calculations using an equation of state (EOS) simulator; (3) systematic validation of the new modeling approach with laboratory studies; (4) evaluation of a hybrid Low Salinity ASP recovery process; and (5) robust optimization of ASP field-scale design under geological uncertainties.

We used a new approach that can model the behavior of the surfactant-oil-water-microemulsion system based on solubility data. In the Type III system, the emulsion is distributed judiciously between the oil and water phases without the need to introduce a third liquid phase. This model captures most of the important physical and chemical phenomena in the ASP process. The model was then validated with numerous coreflooding experiments conducted by different research institutes as well as with a specialized chemical flood simulator. The newly proposed model is tested using different injection schemes and chemical formulations including negative salinity gradient, non-negative salinity gradient, and a series of benchmark coreflooding experiments. Excellent agreements between the model and the experiments in terms of oil recovery and pressure drop were achieved for all corefloods. In addition, the model was also proven to be highly consistent with both UTCHEM-EQBATCH and UTCHEM-IPHREEQC. More importantly, previous results obtained without the explicit modeling of Type III indicated that the recovery factor deviates significantly from the experimental data, whereas the pseudo two-phase approach in this paper gives an excellent match in all cases. This model has also been successfully applied to match the recovery of Alkaline-CoSolvent-Polymer flooding, which is a promising recovery approach.

We investigated the potential of hybrid low salinity ASP flooding in which Low Salinity Waterflooding (LSW) was implemented in secondary production and followed by ASP flooding. This approach can provide a superior performance compared to the conventional chemical flooding because it provides better oil recovery in the secondary stage and promotes the synergy between low salinity environment and ASP slugs. Finally, the proposed robust optimization workflow helps to increasea project NPV and significantly reduces the uncertainty range associated with geology.
Offline Temporary Abandonment, Deepwater DVA
Authors: Hosli C. , Shannon S. , Boyle R. , Stein D.
Published: October 2017

The decommissioning of wells and restoration of natural subsurface barriers which prevent hydrocarbon flow to surface, is a critical activity in well life which removes environmental impact for the future after oil/gas production facilities have been removed. Despite reduced rig/equipment costs, abandonment continues to be a substantial expenditure and represents a significant liability for operators in a cash constrained environment. While we see many efforts to reduce scope of abandonment and workover operations, engineered design and execution must comply with regulations as defined in the Code of Federal Regulations (CFR) without compromising safety.

Abandonment and workover activities in the deepwater Direct Vertical Access (DVA) environment are typically conducted with a platform installed rig. However, there exists a significant amount of work involved in rig workover activities (cement plug installation, tubing cutting, circulation to workover fluid, etc) which do not require the physical workover unit itself and therefore can be accomplished "offline" both to save rig days, cost, personnel exposure, etc. In this context, "offline" will be defined as the time associated with activities that may be accomplished without dedicating critical path rig time to abandonment scope, reducing time and cost, assuming this identified rig would not otherwise be idle. Saved time may be used to provide value in a number of capacities from drilling and completing new wells to working over or abandoning another well.

This paper discusses the case histories of two wells accessible via a deepwater Tension Leg Platform (TLP) in the Gulf of Mexico (GoM), both of which were scoped for conventional producer zonal abandonment and recompletion/workover activities. One would be worked over to another target production zone ~7000’ up-hole while the other would be worked over and converted into a new field injector for a major water flood project in the region. Through meticulous pre-planning, engineering design, and contingency development, the engineering and operations teams working on these two wells were able to reduce the critical path time of the work unit by realizing offline opportunities.

These activities utilized conventional intervention techniques of slickline, electric line, and available pumping to both abandon these wells in an unconventional manner and ready the wells for immediate tubing pull once the rig was skidded atop. This was all done with full compliance with the CFR, in a "through-tubing" method, and satisfied abandonment conditions and operational safety requirements of the operator. While both wells noted significant savings either to acceleration of operation timeline or of first oil, the work conducted required decisive challenge management to succeed. The engineering decisions made, scope reductions identified, and trouble time events incurred will be discussed to the detail possible in this manuscript.
Enhancing Performance and Operational Safety of Argentinean Vaca Muerta Shale Wells by Drilling High Pressure Formations Using Managed Pressure Drilling
Authors: Pozo Mariano , Torres Fabian , Bedoya Jorge , Leroy Jean Christophe , Montilva Julio
Published: October 2017

An unconventional shale gas drilling project in the Rincon de la Ceniza onshore field is being developed to reach the Vaca Muerta formation, which is overlaid by the shallower and troublesome Quintuco formation. This formation is composed of two over-pressurized layers located in the middle and near the bottom of the formation. The Lower Quintuco formation may also be naturally fractured, containing oil and gas, trapped in an over-pressurized regime, creating an operational drilling hazard. Pore pressure prediction has a high degree of uncertainty, making the proper mud density selection a difficult task. Offset wells drilled conventionally have incurred significant Non Productive Time (NPT) due to well control events, where accurate kill mud weight definition has been challenging due to the presence of natural fractures.

The objective for the drilling campaign was to define an optimal and reliable drilling method that would address the challenges of pore pressure uncertainty in a safe and cost-effective way. The first step was to implement Managed Pressure Drilling (MPD) to control over-pressurized zones and determine the more suitable mud density to control the well. The previous vertical wells were drilled conventionally having Quintuco and Vaca Muerta formations isolated from each other with two different casing strings.

The drilling strategy was redefined and implemented in three horizontal wells, but in this time both formations were drilled together in one hole section. The intention was to enable drilling with the minimum mud weight possible, allowing higher Rate of Penetration (ROP) consequently. This was possible to achieve by maintaining constant bottom hole pressure conditions at variable Anchor Point depths along the open hole while drilling Quintuco formation. Before drilling the horizontal section in Vaca Muerta formation, a small and controlled constant underbalanced condition was created and fixed at the deepest Anchor Point depth which was as close as possible to the transition zone between both formations.

This successful strategy allowed improving drilling performance, by reducing drilling time from 123.4 to 51.7 days per well and reducing NPT from 30.5% to 7.5% by managing well control events, eliminating one casing string and improving drilling efficiency to increase the ROP. Consequently, the cost of the well was reduced 5.5 MM USD/well when compared with the last well of the campaign without any Health Safety and Environment (HSE) issues.

This paper presents the drilling strategy followed to overcome well control events and associated NPT when drilling an unconventional shale gas play with highly uncertain pore pressure profile. Planning, implementation and results from the project are presented.
Fact-Based Energy Education for Non-Technical Students
Authors: Fanchi John R.
Published: October 2017

This paper describes an energy education course that has been designed for the general college student population. The course entitled Energy in Society provides a fact-based analysis of the most prominent energy issues of our time. Consequences of our choices are examined with respect to their effect on the economy, society, and the environment. The pedagogy, course description, and student feedback are provided in this article.
Advancing Electric Submersible Pump Alternative Deployment Technology: An Overview and Case Study
Authors: Roth Brian A. , Xiao J. J. , Windiarto Yhossie , Al-Hadrami Naif , Al-Qahtani Nasser F. , Sarawaq Yahya
Published: October 2017

Traditional electric submersible pump (ESP) systems have drawbacks in terms of installation speed and efficiency. To overcome these obstacles, some alternatively deployed ESP systems, including the one selected, are deployed into the production tubing, subjecting the system to the properties of the produced fluids. A novel rigless-deployed ESP system developed for use in high hydrogen sulfide (H2S)/high chloride production environment is a solution.

An initial step reviewed and ranked competing alternate deployment ESP technologies available in industry along with several new concepts. A new approach to alternate deployment technology was selected. Rigorous testing was conducted to qualify the selected technology and materials for harsh production environments. Testing included a modified NACE TM0175 test due to the processing of the power cable design. Integration testing was performed in a test well to validate the integrity and deployment of the new system prior to field deployment of the rigless-deployed ESP system.

The cable deployed ESP (CD ESP) employs a fit-for-purpose power cable that incorporates an exterior metal jacket, providing strength to deploy ESPs thousands of feet into the well. The TransCoil system's power cable outside diameter is roughly 40% smaller than current 2-3/8-in cable-internal, coiled-tubing (CICT) systems; therefore, it is lighter in weight and reduces tubing pressure losses compared to previous products. Product reliability is enhanced as the power cable is fabricated in a continuous manufacturing and inspection process on a factory floor. The tightly controlled manufacturing process significantly improves the product quality over CT cable systems. The power cable can be fabricated from different metallurgies ranging from carbon steel to nickel allow based on the well requirements. A nickel alloy power cable laboratory qualified to 15% H2S and 150,000 ppm chlorides was field deployed in an onshore well and demonstrated an installation time reduction of nearly 50% over rig-deployed systems.

A power cable rigless-deployed ESP system solves many of the challenges that currently plague the industry including operational efficiency, rapid replacement, and product reliability in wells in harsh environments worldwide. The power cable rigless-deployed ESP system has, in particular, the opportunity to transform ESP replacement in offshore wells.
Nanoparticle-Stabilized Foams for High-Temperature, High-Salinity Oil Reservoirs
Authors: Singh Robin , Mohanty Kishore K.
Published: October 2017

The goal of this work is to develop foams stabilized by a combination of nanoparticles and surfactants for high-temperature, high-salinity reservoirs. Two types of silica nanoparticles (LNP1, LNP2) with different grafted low molecular weight ligands/polymers were used. First, aqueous stability tests of these formulations were performed at high-temperature (80 °C) and high-salinity conditions (8 wt% NaCl and 2 wt% CaCl2). The screened nanoparticles were used in combination with a surfactant. Second, bulk foam tests were performed to evaluate their foaming performance in bulk. Finally, oil displacement experiments were conducted in an in-house, custom-built 2D sand pack with flow visualization. The sand pack had two layers of silica sand — top layer with 40-70 mesh and bottom layer with 100-120 mesh, which resulted in a permeability contrast of 6:1. Water flood with subsequent foam flood was performed. The grafting of low-molecular-weight polymers/ligands on silica nanoparticle surfaces resulted in steric stabilization under high-temperature and high-salinity conditions. In the oil displacement experiments in the layered sand packs, the water flood recoveries were low (~33% OOIP) due to channeling in the top high-permeability region, leaving the bottom low-permeability region completely unswept. Foam flooding with just the surfactant leads to a drastic improvement in sweep efficiency. It resulted in an incremental oil recovery as high as 43.3% OOIP. Different cross-flow behaviors were observed during foam flooding. Significant cross-flow of oil from low-permeability region to high-permeability region was observed for the case of surfactant. Conversely, the LNP2-surfactant blend resulted in no crossflow from the low permeability layer with complete blocking of the high-permeability region due to the formation of in-situ emulsion. Such selective plugging of high-perm channels via nanoparticles with optimum surface coating has significant potential in recovering oil from heterogeneous reservoirs.
Effect of Nanoparticles on Flow Alteration and Saturation during CO2 Injection and Post Flush
Authors: Zhang Xing , Tian Fa-guo , Zhou Hong , Du Hong-ling , Ding Chao , Wang Jing , DiCarlo David A.
Published: October 2017

We observed that the mechanism appears to be spontaneous generation of nanoparticle-stabilized droplets of the injected phase, which increases the effective viscosity of that phase. In this paper, we combine water alternating gas and nanoparticles to look into whether the presence of nanoparticles results in more CO2 being trapped, after an additional flood with brine.

This paper concludes two experiments to study the transport behavior of nanoparticles. In the first experiment, CO2 was used to displace 2 wt% NaBr solution in a cylindrical core (diameter 7 cm, length 30 cm) of Boise sandstone (porosity 27.5%, permeability 1D), and then post flush with NaBr solution. For the second experiment, CO2 was used to displace the 2 wt% NaBr and 5 wt% nanoparticles solution in the core, and then post flush with nanoparticles solution. Dynamics of the displacement front and pressure drop across the core were measured in real time with CT scanner and pressure transducers respectively.

Different front dynamics are seen of wetting and nonwetting phases and the stabilizing front is generated by Roof snap-off events. When CO2 displaces brine in which surface treated silica nanoparticles, the initial and residual CO2 saturation are higher than that of the brine without nanoparticles. And the C constant of Land-curve is 2.2 and 2.4 respectively in the nanoparticle case and control case. The results suggest that pre-positioning a dispersion of nanoparticles in the brine will be potential for mobility control in CO2 storage and CO2 EOR, and can eventually be used in engineering CO2 injection protocols.

Introducing engineered nanoparticles into an aquifer or reservoir can potentially control the fluid mobility in CO2 storage and CO2 EOR. This provides an interesting alternative approach for mobility control in CO2 EOR which would work well with WAG processes. Moreover, the same process can increase enhance the residual trapping of CO2 and therefore increase the number of competent formations for secure CO2 storage.
Reservoir Fluid Characterization Procedure for PC-SAFT Equation of State
Authors: Tybjerg Peter , Pedersen Karen S. , Pedersen K. Schou
Published: October 2017

A C7+ characterization procedure reservoir oil mixtures is presented for the PC-SAFT equation of state. The plus fraction of a reservoir fluid composition is split into carbon number fractions and the PNA distribution estimated of each C7+ carbon number fraction. For each component class (P, N, and A) a constant ε parameter is used independent of molecular weight while the parameter m is assumed to increase linearly with molecular weight. The m and ε parameters of the individual component classes are combined into one value, representative of the whole carbon number fraction. To ensure reliable density predictions, the parameter σ is determined to match the density of each carbon number fraction at standard conditions. The procedure has been tested on ten oil compositions originating from the North Sea, Gulf of Mexico, and the Middle East. For those oil mixtures the PC-SAFT equation provides more accurate liquid compressibilities and liquid densities and shows a more correct development in saturation pressure with temperature than the SRK-Peneloux equation. For near critical mixtures, including oil mixtures undergoing gas injection for EOR purposes, the PC-SAFT equation is less suited than a cubic equation. Asphaltenes require lower values of the PC-SAFT m-parameter than non-asphaltene aromatics. Parameter tuning is needed to use the PC-SAFT equation for gas condensate mixtures.
Understanding the Deviation of Horizontal Wolfcamp Well GOR from Type-Curve GOR in the Gas-Condensate Region of the Permian Basin
Authors: Gaurav Abhishek
Published: October 2017

The objective of this work is to explain the deviation in GOR/GLR (Gas-Oil-Ratio/Gas-Liquid-Ratio) of hydraulically fractured Wolfcamp horizontal shale well(s) from the type-curve GOR/GLR in the gascondensate region of the Permian Basin.

We relied on the detailed field data reported during the flow-back period of a recently completed well. We identified various aspects of the casing-tubing design, operational changes that were made and any concurrent production disturbance that were noticed. Then we did a thorough literature review of GOR/GLR behavior in gas condensate wells. We identified the key concepts that were applicable to the well in our study. We applied the existing equations for the critical gas rate required to lift liquids in gas wells and highlighted the variation in gas velocity with changing pressure and temperature along the vertical part of the wellbore. Using this approach, we demonstrated the relationship between changing liquid fraction along the vertical part of the wellbore with the changing gas velocity.

A wide range of GOR/GLR was noticed for the well in our study over a period of only a few days of flow- back. The GOR/GLR curves from the nearby producing wolfcamp wells and the PVT diagram available from a nearby wolfcamp well could not explain the observed deviations in GOR/GLR. However, there were some key changes made in the production methodology during the flow-back period. We identified the appropriate mechanisms of multi-phase flow applicable to each operational change during flow back. After identifying the appropriate multi-phase flow back mechanism, we implemented the concept of critical gas velocity (flow-rate) along the wellbore. This enabled us in explaining the GOR/GLRs observed in each operational regime. The corrected GOR/GLR of the well in study aligned with the GOR/GLR of the type-curve of horizontal shale wells obtained from the nearby hydraulically fractured horizontal wells targeting the Wolfcamp in the same formation.

This is a unique study that utilizes the concept of critical flow rate, the different mechanisms of multiphase flow in the production tubing and annulus in identifying the advent of liquid loading. This work assists in explaining the discrepancies observed in the GOR/GLRs in the early production history of horizontal gas wells in gas-condensate regions. In the past, the concept of liquid-loading and the proposed remedies have been applied late in the life of gas wells with small gas rates to explain the abnormaility of the the GOR/GLR. This paper shows that the observed GOR/GLRs on the surface is not solely a function of the PVT diagram. Finally, integrating the learnings from this well with the liquid-loading concepts, we make recommendations for improved completions and flow back methodology for future wolfcamp horizontal gas-condensate wells in the Permian Basin.
Continuous High Frequency Measurement Improves Understanding of High Frequency Torsional Oscillation in North America Land Drilling
Authors: Zhang Z. , Shen Y. , Chen W. , Shi J. , Bonstaff W. , Tang K. , Smith D. L. , Arevalo Y. I. , Jeffryes Benjamin
Published: October 2017

Bit and bottom hole assembly (BHA) rotational speed oscillation is often encountered in North America land drilling applications. One common type of rotational speed oscillation is the well-known stick-slip, with speed variation at a frequency that is close or lower than the fundamental torsional natural frequency of the drillstring (usually less than 1Hz). Another commonly encountered rotational speed oscillation confirmed by the authors' recent studies is the high frequency torsional oscillation (HFTO), with a frequency ranging from 10's to over 100 Hz. This paper will discuss new findings on HFTO.

Most of the commercially available downhole measurement tools have no difficulty picking up the low frequency stick-slip, but lack bandwidth to detect HFTO. Also it is rarely observed from the surface instruments because high frequency torsional wave can be dampened quickly when it is transferred along the drillstring. Hence, HFTO could be misinterpreted as smooth drilling until tool failure or damage occur.

To understand the mechanism of HFTO, a series of downhole tests were conducted in North America land with different BHA setups and applications. An advanced downhole measurement tool was placed in the BHA to continuously record tri-axial acceleration and rotational speed at 1024 Hz sampling rate. After extensive analysis performed on the downhole high frequency data, we present in this paper many interesting findings. HFTO shifts frequency depending on different downhole conditions. There is a strong correlation between the surface parameters (RPM and SWOB) and the occurrence of HFTO. The excitation of HFTO is also related to the formation. 3D transient drilling dynamics simulation confirms the factors that increase the risk of HFTO.

Based on this study, we provide recommendations to downhole measurements for capturing HFTO. With real-time HFTO detection, drilling parameters can be adjusted to reduce the chance of HFTO to avoid premature tool failures. We also provide insights for new tool development to obtain better tool life by eliminating weak spots and perform more robust measurements by selecting better sensor locations, etc. With the help of 3D transient dynamic modeling, we can gain better understanding of HFTO mechanisms through numerical simulation, making it possible to plan the BHA effectively and select drilling parameters to avoid HFTO.
Application of Pin-Point Sand Jet Perforating Annular Fracturing in Multiple Coal Seams Unleashing Clean Energy in Southwest China
Authors: Lee K. K. , Chen J. L. , Liu Y. J. , Li Y. K. , Zeng X. Z. , Zhou B. , Hu G. , Wang S. L.
Published: October 2017

Guizhou Province which located in the southwest China is one of China's least developed but fastest growing provinces, has large reserve potential for Coal Bed Methane (CBM) but yet, the natural gas utilization is among the lowest in China. The exploitation of CBM resources in the province started since early 90's, but no substantial breakthrough has been achieved. Among all the challenges encountered in the attempt to develop the resources, one key challenge is on how to frac stimulate the coal seams effectively. The high coal-rank CBM reservoirs commonly contain low permeability multiple thin coal seams that require frac stimulation to flow. However, conventional blanket-type frac treatment via pumping down casing at high rate has been shown to leave some coal seams untreated and not contributing.

Pin-point fracturing using coiled-tubing allows multiple precisely targeted coal seams to be treated, which can increase gas flow rate and reserve, and significantly shorten time cycle as compare to conventional casing frac method. Three CBM wells in the north-west Guizhou province in China have been pin-point stimulated using coiled-tubing producing gas at an encouraging rate compared with conventional method.

This paper discusses how the pin-point fracturing technique been introduced for the very first time to Guizhou CBM wells, the details of the concept, fracturing process, operational methods, treatment outcome of the field trial, and how the technology could shape the future of CBM exploitation strategy in Guizhou Province.
Recurrent Neural Networks for Permanent Downhole Gauge Data Analysis
Authors: Tian Chuan , Horne Roland N.
Published: October 2017

The rich information contained in permanent downhole gauge (PDG) data has drawn attention from researchers. Previous work has demonstrated feature-based machine learning to be promising for PDG data analysis. The recent rise of deep learning was powered by techniques including recurrent neural networks (RNNs), which have been shown useful for processing sequential information. In this work, we explored how RNN can be utilized to analyze PDG data for better reservoir characterization and modeling, by examining two specific RNN structures: nonlinear autoregressive exogenous model (NARX) and standard RNN.

RNN is a special type of artificial neural network designed for sequential data processing. Unlike a nonrecurrent neural network, the hidden layers in RNN take memories of previous computations (e.g. hidden layers or outputs computed in previous time) into account. In that way, the information contained in the measurements prior to a certain time can be used to model the response at that time, i.e. the convolutional effects are modeled by the recurrent structure of the RNN. Another favorable property of RNN is that it requires no assumptions on physics in advance. Both the inputs and outputs come directly from the raw measurements, and no handcrafted features need to be extracted from the forward physics model. Compared with feature-based machine learning, RNN is more powerful for the modeling where the forward model has not been determined.

In this work, RNN was first tested on a series of synthetic and real flow rate-pressure datasets. The patterns learned by RNN from those data helped correctly identify the reservoir model and forecast the reservoir performance. RNN was also applied on temperature transient data, to demonstrate its advantage over feature-based machine learning with no assumptions on the physics model. The study also showed that RNN has the noise tolerance and computational efficiency that make it a promising candidate to analyze PDG data in practice.
The Development of a Coupled Geomechanics and Reservoir Simulator Using a Staggered Grid Finite Difference Approach
Authors: Gao C. , Gray K. E.
Published: October 2017

For a stress-sensitive reservoir, the constant rock compressibility term used in a conventional reservoir simulator (CRS), does not account for change of porosity and permeability. This paper develops a coupled geomechanics and reservoir simulator (CGRS) which accounts for changes in porosity and permeability related to deformation.

The simulator in this paper adopts a staggered grid finite difference method for fluid flow and displacements. Displacements and pore pressures are placed at centers of faces and grid blocks, which increases numerical accuracy. Four types of nonlinear, coupled equations (porosity, permeability, displacements, and pressure equations) have been derived for use in CGRS. The Newton-Raphson method requires solving all the unknowns simultaneously, a computationally intensive procedure. An alternative is to use the Macro Gauss-Seidel method, which divides a huge nonlinear matrix into several smaller matrices, thus speeding up computations.

Solutions from CGRS have been validated using two analytical solutions: a one dimensional consolidated reservoir and an idealized reservoir. This validated simulator is used to simulate a 3D reservoir with multiple vertical and horizontal wells. The comparison between CRS and CGRS shows that pressure depletes faster in CRS as compared to CGRS. CGRS results in higher bottom-hole pressure for a constant rate well. Constant rate wells yield a result of 1 to 1.26 times higher bottom-hole pressure than CRS. This shows that neglecting geomechanics effects in CRS can lead to an under prediction of reservoir/bottom hole pressures and production rates. Another powerful function of CGRS is the output of 3D displacements, which cannot be predicted by CRS. After producing for 1000 days, the maximum vertical displacement reaches 0.34 ft. (0.085% of reservoir thickness). Maximum displacements in the x and y directions (lateral displacements) are 4 × 10-4 ft. and 0.015 ft., both of which are smaller than vertical displacement because of fixed lateral boundary conditions.

Unlike traditional iterative coupled (IC) methods, fluid flow and geomechanics share the same mesh, which solves the problem of numerical instability in two discretization methods used in traditional IC. Also, the change of volumetric strain with respect to time (usually neglected in traditional IC) has been included in the fluid flow equation to better characterize the effects of solids movement on fluid flow. The Macro Gauss-Seidel method was adopted to increase computation efficiency of the simulations. The simulator introduced in this paper has its own data structure for geomechanics analysis which can be incorporated in single-phase, two-phase, three-phase or compositional reservoir simulators.