bluuebunny/crossref_metadata_2025_split huggingface dataset:
Efficient Integration Method of Large-Scale Reservoir Compaction and Small-Scale Casing Stability Models for Oilfield Casing Failure Analysis
Authors: Yamada Kenta , Furui Kenji 
Published: October 2018

Abstract
Many casing failure incidents have been reported in oil and gas fields around the world. These casing failure events can occur not only within reservoirs but also in surrounding formations. Engineers must evaluate risks of casing failure when drilling and completing wells especially in highly compacting reservoirs. However, one of the challenges encountered during the evaluation of casing failure risks is that field-scale stress changes and displacements as a result of drilling wells and producing hydrocarbon from reservoirs must be properly taken into account for casing stability analysis. The objective of this study is to develop an efficient integration method for large-scale reservoir compaction and small-scale casing stability analyses for the evaluation of casing deformation and failure.
The numerical model developed in this work is based on 3D elasto-plastic finite element method (FEM). Reservoir compaction and subsidence are analyzed using a large-scale FEM model considering details of geological settings while casing stability is analyzed separately by a small-scale FEM model. The two FEM models are integrated by interpolating displacements calculated by the large-scale model and assigning resultant displacements for boundaries of the small-scale casing stability analysis model. The validation of the proposed integration method is also presented in the paper.
Our study results indicate that the integration method presented in this paper significantly improves computational efficiencies on an order of 5 times faster than the conventional simulation method that requires a large number of finite elements for reservoir, surrounding formations, cement, and casing. Also it is demonstrated that the integrated model can be applied to inclined wells completed in highly heterogeneous formations at sufficient accuracy. The field case study also indicates that the risk of casing deformation highly depends on its inclination and the position relative to the compacting formation.
The small and large scale coupling method developed in this work helps engineers evaluate casing deformation and failure in various locations in reservoir and surrounding formations in an efficient manner and also develop safe and efficient drilling and completion programs to reduce risk of casing mechanical problems.
Relative Permeability Curve Shapes in Coalbed Methane Reservoirs
Authors: Salmachi Alireza , Clarkson Christopher , Zhu Suyang , Barkla James Ashton 
Published: October 2018

Abstract
Relative permeability curves in coalbed methane reservoirs (CBM), acquired by analysis of production data, can differ from laboratory-measured curves due to complications such as stress-desorption dependent permeability and cross-formational flow. This paper aims to derive relative permeability curves for coalbed methane reservoirs using production data analysis, as well as discuss curve characteristics and shapes. Field examples from the San Juan Basin in the US and the Qinshui and Ordos Basins in China are presented to provide a worldwide view of relative permeability curve shapes. These field examples are analysed using a tank type model, a common production data analysis tool, and the influential factors on curve shapes are discussed. The results and analysis indicate that permeability enhancement during the life of the well, and cross-formational flow between the coal seam and adjacent formations, can strongly control curve shapes. These effects, when not detected, can result in irregular relative permeability curve shapes obtained by analysis of production data. Direct measurement of permeability enhancement requires time-lapse production tests while investigation of cross-formational flow of water into coal seams requires hydraulic connectivity assessment, which are time consuming and expensive to conduct. The signatures of relative permeability curves presented in this study allow indirect determination of permeability enhancement and cross-formational flow in coal seam gas reservoirs.
A Novel Nanosilica-Based Solution for Enhancing Mechanical and Rheological Properties of Oil Well Cement
Authors: Qalandari R. , Aghajanpour A. , Khatibi S. 
Published: October 2018

Abstract
The main purposes of employing cement in oil wells are to isolate the zones within formations, secure casing from axial loading and corrosion and improve wellbore integrity. There are plenty of nanomaterials represented in the literature which were introduced to cement in order to advance the strength and rheological properties of cement slurry. The objective of this study is to propose a novel nanomaterial which can upgrade the mechanical and rheological properties of cement. The smaller the size of Nano-particles, the higher surface area and hence higher efficiency they possess to advance particular properties of the support material. Bio-templating has been offered as an approach to reduce the size of utilized nanoparticles. In this study, Nanosilica particles were synthesized and functionalized using modified sol-gel method. Bio-templating was then implemented through crosslinking of the procured Nanosilica with soluble egg protein using glutaraldehyde. In order to investigate the effect of bio-templated Nanosilica on cement slurry, synthesized Nanosilica was added to cement and rheological and mechanical experiments were conducted. To validate the performed bio-templating, ATR-FTIR spectrum was acquired which confirmed successful crosslinking between the functionalized Nanosilica and SEP. Furthermore, experimental tests were conducted to evaluate the effect of bio-templated Nanosilica on mechanical and rheological properties of neat cement. The results were then compared to inclusion of commercial Nanosilica in cement. Through the rheological studies, it was found that the modified Nanosilica has acted as dispersant in cementitious system by decreasing the plastic viscosity of cement and maintaining the density. It was also obtained that novel bio-templated Nanosilica has significantly increased uniaxial compressive strength of cementitious system by 16.59% upon addition of only 0.25 wt.%. It was due to its pozzolanic reaction in cement and its pore filling effect where the porosity of cementitious system was decreased. The proposed synthesized Nanosilica demonstrates superior results than commercial Nanosilica which shows its remarkable efficiency in cement strength reinforcement and rheological properties improvement. The research study has successfully proposed a novel method to utilize biomaterial waste in the process of synthesizing Nanosilica particles which is not only environmental friendly but also yields in phenomenal rheological and mechanical properties of Class G cement.
Evaluating Natural Gas-Based Foamed Fracturing Fluid Application in Unconventional Reservoirs
Authors: Pankaj Piyush , Phatak Alhad , Verma Sandeep 
Published: October 2018

Abstract
Foamed fracturing fluids have been used in unconventional reservoirs to reduce the water use and minimize deleterious impact on water-sensitive formations. As part of a Department of Energy (DOE) sponsored program, we previously identified an optimal thermodynamic pathway to transform wellhead natural gas (NG) into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid. This study now aims to extend that work by determining the impact of using NG foam fracturing fluids on hydraulic fracture geometry and on productivity from the unconventional reservoirs.
The current study is focused on investigating the impact of the NG-based foam of various foam qualities in hydraulic fracture geometries and their production through simulation models. Field data and laboratory-based measurements for NG foam fluid properties are incorporated in the study. In addition, the transient response of the fluid flowback from foam-based fluid is studied using numerical simulation. Comparative analysis is done with typical slickwater, linear gel, and crosslinked fluid application for hydraulic fracturing using 3D-complex hydraulic fracture models. 1D and 2D particle transport models have been used to verify the differences in proppant distribution in the hydraulic fractures.
Rapid wellbore clean-up, low formation damage, and effect of the relative permeability improvement are added advantages apart from reducing the water requirements for hydraulic fracturing. In addition to providing the logistical benefit of using wellsite liberated low pressure gas, NG foamed fracturing fluid has a dynamic fluid leak-off behavior and increased effective viscosity over the base fluid that allows pumping and transporting proppant at least 10% farther in the hydraulic fractures than linear gel. Slickwater displays poor proppant transport and hence poses inability to pump higher concentrations of sand. NG foam fracturing fluid on the other hand displays improved proppant transport and has been shown to create more complexity than slickwater in our simulations.
Use of NG foamed fracturing fluid has not been practiced widely yet. Application of NG Foaming field test and reaping the economic benefit from simplified logistics and improved production would enables operators to invest in creating a safer handling environment for wellsite application of NG foam.
An Online Water Cut Measurement System Based on the Conductance Sensor
Authors: Yang Qinghai , Li Ming , Wang Quanbin , Meng Siwei , Ming Eryang 
Published: October 2018

Abstract
The conductance sensor based water cut meter is usually used to measure content of the oil-water two phase mixed fluid for periodical well production logging. In order to solve the real-time monitoring problem of downhole water cut, this paper proposes an online water cut measurement system based on the conductance sensor technology. Through the newly developed system, the continuous and permanent water cut measuring can be realized. The system consists of two conductance sensors, one temperature sensor, sampling mechanism and control & storage unit. Due to different density of oil and water, the two conductors with cylindrical poles, equipped on the upside and downside of the fluid inlet respectively, sense the conductivity of the oil-water mixed fluid and the detached water. With the real-time sampled downhole temperature, the conductivity values are compensated to reflect the real characters of the two kinds of liquid. According to Maxwell's model of oil-water mixed fluid and the correction parameters from offline calibration, the water cut is deduced. Since all units are designed with low-power consumption and high protection level, the system can operate permanently and provide online monitoring values. The water cut measurement system is tested in a physical testing environment with different conditions of the oil-water mixing ratio, the mineralization degree of water, the liquid temperature and the flow rate. Testing results show that the water cut in oil-water mixed fluid and the sampled conductivity follow the Maxwell's model approximately, where the error between testing data and theoretical value is within 3% especially for the high water cut cases. When the temperature changes, the measured water cut value basically does not variate, although sampled conductivity of the two sensors change a lot with temperature. Different mineralization degree of water would affect the measured water cut result slightly, which should be due to the conflicts between the large conductance range and the sampling accuracy. The flow rate is another element to make the measured result fluctuation, but the water cut would be stable when using the average value within a period. In brief, the system provides real-time water cut measurement and the measuring accuracy can satisfy the requirements of petroleum production. The conductance sensor based water cut measurement system realizes real-time measuring of oil-water mixing ratio for oil production and can provide online parameters for optimizing production process rapidly. All electronic units are designed with low-power consumption, which ensure the system to run downhole permanently.
Volume Change of Cement Plugs: Spotlight on the Role of Boundary Conditions Using an Improved Testing Method
Authors: Jandhyala Siva Rama , Pangu Ganesh , Deshpande Abhimanyu , Wolterbeek Tim , Cornelissen Erik , van Eijden Jip 
Published: October 2018

Abstract
Expansion additives have been used in cement plugs to mitigate the potential risk of plug failure resulting from shrinkage. These additives are effective only when their amount is tailored for downhole boundary conditions, and their role should be well understood. This work discusses using an improved testing method that enhances the dependability of the volume change measurement and exhibits the impact of test boundary conditions on the shrinking and expanding behaviors of cement plugs.
Boundary conditions investigated with this method include temperature, pressure, water access to the cement from the formation, and the role of mechanical constraints. Dependability is demonstrated by verifying the repeatability and reproducibility of the method at two different laboratories. Together with the noninvasive continuous volume change, supplementary measurements, such as ultrasonic compressive strength, tensile strength, and chemical composition analysis, have provided inferences about the mechanism of volume change.
The new method embodies all attributes listed in API 10 TR2 (1997), including a constant external stress state in all measurements and a constant pore pressure during total volume change measurement. The results of percentage volume change from this test method present an extremely small variance, highlighting its repeatability; additionally, the measurement was reproducible between laboratories. Expansion value increased with a decrease in confining pressure, and excessive expansion in the absence of an effective confining pressure produced weak samples. The absence of outside water caused cement containing the expansion aid to shrink more than its neat equivalent; such observations highlight the importance of fluid boundary on the action of expansion additives.
These observations were possible because the test method can capture temporal and boundary condition effects more aptly. Thus, the improved method provides a dependable measurement for tailoring plug properties.
Improved Numerical Stability and Upscaling of Low Salinity Water Flooding
Authors: Al-Ibadi Hasan , Stephen Karl , Mackay Eric 
Published: October 2018

Abstract
Numerical stability and precision are required when using simulations to predict Enhanced Oil Recovery processes and these can be difficult to achieve for Low Salinity Water Flooding (LSWF). In this paper we investigate the conditions that lead to numerical instabilities when simulating LSWF. We also examine how to achieve more precise simulation results by upscaling the flow behaviour in an effective manner.
An implicit finite difference numerical solver was used to simulate LSWF. The stability and precision of the numerical solution has been examined as a function of changing the grid size and time step. We used the Peclet number to characterise numerical dispersion with these changes. Time step length was compared with the Courant condition. We also investigated some of the nonlinear elements of the simulation model such as the differences between the concentrations of connate water salinity and the injected brine, effective salinity concentration range and the net mobility change on fluids through changing the salt concentration.
We observe that numerical solution of LSWF tends to be conditionally stable, with problems occurring as a function of the range of effective salinity concentration relative to the initial reservoir water and the injected brine concentrations. We observe that the Courant condition is necessary but not sufficient. By definition, the precision of the numerical solution decreased when increasing numerical dispersion but this also resulted in slowing down the low salinity water and increased the velocity of the formation water further reducing precision. These numerical problems mainly depend on fluid mobility as a function of salt concentration. We conclude that the total range and the mid-concentration of effective salinity affect the stability and precision of the numerical solution, respectively. In this work, we have developed two approaches that can be used to upscale simulations of LSWF and tackle the numerical instability problems. The first method is based on a mathematical form that gives the relationship between the fractional flow, effective salinity concentration and the Peclet number. The second method is that we have established an unconventional proxy method that can be used to imitiate pseudo relative permeabilities.
This work enables us for the first time to simulate LSWF by using a single table of pseudo relative permeability data, instead of two tables as traditionally done in previous studies. This removes the need for relative permeability interpolation during the simulation and will help engineers to more efficiently and accurately assess the potential for improving oil recovery using LSWF and optimise the value of the field development. We also avoid the numerical instabilities inherent in the traditional LSWF model.
Use of Probabilistic Methods to Assess a Portfolio of Conventional and Unconventional Resources
Authors: Jones Alistair , Mijnssen Chris , Burton Andrew , Ewin Mark 
Published: October 2018

Abstract
Recoverable hydrocarbon resource assessments underpin decision making and business planning in the oil and gas industry. Understanding the uncertainty associated with the resource assessments are key to sound decisions that are robust against low or high outcomes. This paper outlines a probabilistic approach to resource assessment in order to characterise resource uncertainty in a portfolio containing primarily Coal Seam Gas resources.
The Probabilistic Resource Assessment (PRA) process outlined in this paper allows calculation of risked and unrisked probabilistically derived commercially recoverable resources at a field or permit level as well as at a portfolio level. This process incorporates Undiscovered ("Prospective") resources and Contingent Resources as well as resources that are producing or are under development. The key steps in this process include: definition of input distributions, probabilistic calculation of technically recoverable resources at a field level, estimation of economic chance of success, probabilistic estimate of commercially recoverable resource and aggregation of resources to a portfolio level.
This process has been applied within an integrated joint venture supplying Liquefied Natural Gas (LNG) and domestic gas markets. The process has been used primarily to understand the uncertainty range of the total resource as well as the production profile within the upstream portfolio. Sensitivities to product prices or development costs can be investigated to enable a deep understanding of the key drivers and variables of the resource assessment.
Various methods for determining recoverable hydrocarbon resources have been well documented. Broadly speaking, these methods can be categorised as probabilistic methods and deterministic methods. Typically, unconventional resources are assessed using deterministic methods. The process presented here is a robust probabilistic approach to determine a risked view of recoverable resources within an entire portfolio including both unconventional and conventional resources.
Cementing Production Liners Terminating in Depleted Reservoirs: A Case Study on Deepwater Wells off the East Coast of India
Authors: Yadav Anand , Kumar Animesh , Iyer Venkat , Ganjoo Tushar , Bhaisora Devesh 
Published: October 2018

Abstract
A lightweight cement solution was successfully applied in deepwater wells at depths greater than 1000 m and in production liners terminating in depleted reservoirs. These wells were drilled off the east coast of India. The fracture gradient prognosis for the depleted zones ranged from 11.0 to 11.28 lbm/gal. The measured depth (MD) of these wells was more than 4500 m (MDRT). Mud weights ranged from 10.9 to 11 lbm/gal in the well while drilling the zone. The length of the liner normally ranged from 1400 to 2300 m. The cement slurry was finalized after conducting numerous tests in the laboratory. A lead and tail combination was used for the job to maintain the required equivalent circulating density (ECD).
In openhole completions, the casing or liner before the gravel pack should be landed in sand to establish having reached the reservoir top and to help ensure that no shale is present. Challenges for a successful liner job in these wells include landing in a depleted reservoir, which would enable a very low margin between the mud weight and fracture gradient. This margin is further reduced by the minimum horizontal stress mud weight requirement to help ensure that no hole collapse occurs while drilling and before cementing begins. In addition to the depleted zone, to maximize reservoir tapping, the well profiles are highly deviated, often reaching a well deviation of 80+ degrees, resulting in a high ECD during cementing. A long section of the cement column can create problems of cement channeling past the mud and mixing in the annulus. The correct prediction of pore pressure and fracture pressure for different sections is very important. Accurate knowledge of these values is recommended for a correct job design.
Some of the lessons learned during the process to help ensure good zonal isolation include the following: An 11-lbm/gal lightweight lead slurry was formulated, keeping ECD and fluid rheology vs. strength development in mind. Solids loading was controlled to help ensure low friction factors (considering rheology) and to achieve a final compressive strength of 2,000 psi because it was a production casing.The length of the tail slurry column was maintained to a minimum to create minimal effect on the ECD, even though the hydrostatic pressure developed was marginal in a highly deviated section.A low-rheology/low-density synthetic oil-based mud (SOBM) (10 lbm/gal) was pumped ahead to reduce the ECD and to maintain the equivalent static density (ESD) above the pore pressure. In addition, the displacement rate was staggered to help maintain the ECDs.A high-viscosity pill was spotted at the 12 1/4-in. section total depth (TD) before the final pullout to act as a base for the cement slurry.
This paper highlights the concerns and best practices developed when cementing production liners across depleted formations in deepwater wells.