bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimal Fracing Near Faults - Quantifying the Interaction Between Natural and Hydraulic Fractures Using Geomechanical Modeling
Authors: Umholtz N.. , Ouenes A..
Published: November 2015

Utilizing the Material Point Method (MPM) and Continuous Fracture Models (CFM), a workflow is presented that combines Geophysical, Geological, and Geomechanical (3G) considerations to address engineering challenges. Fracture models are derived using geologic and geophysical information, as well as mechanical properties. Hydraulic fractures are then simulated and recreate realistic mechanical results. Products of the workflow such as local stress anisotropy and rotations, strain distributions, and the J Integral provide insight into the sometimes unexpected results of fracing efforts, from the standpoint of geomechanics and the impact of natural fracture networks. Considered primarily in this study is the impact of large scale faults on various stages of an unconventional resource's development.

First, in a Wolfcamp study, it is demonstrated that the mechanical activation of a fault known to bring water can be mitigated either by moving the well 640ft further from the fault and accepting an engineered completion which omits two stages still likely to access the fault, or by moving the well over 920 ft to complete the entire length of the well without accessing the fault. A dataset from the Eagle Ford is then used to demonstrate the ability of the workflow to predict 90 degree stress rotations in fault blocks crossed by a well, and suggests how higher stress anisotropies might reduce the ability of hydraulic fracturing to stimulate complex permeability and instead, only access preexisting fractures. Finally, using recently published fault data and seismic data from the Oklahoma Geological Survey, the link between induced seismic events and a geomechanical proxy are explored.

From well placement in relation to a fault, to stage placement in a well which crosses a fault block with a pronounced stress rotation, to prediction of induced seismic events across three Oklahoma counties—the potential of this workflow to address numerous shale concerns is demonstrated. Large scale faults can greatly alter the stress fields, and consequently the potential of a resource-rich rock to be stimulated. These effects are quantified using geomechanical products of the workflow such as stress anisotropy distributions, strain distributions, and the J Integral. The 3G workflow considered here produces multiple geomechanical results which are crucial to a more realistic understanding of how hydraulic fracturing efforts stimulate the reservoir.
Structural Controls on the River Morphology and Sedimentation Pattern in the South Pine River Basin, North Brisbane
Authors: Bhosle B.. , Bhagat D. K. , Barcelona E..
Published: November 2015

Sedimentary deposits and structural control on the depositional pattern in South Pine River basin has been investigated in the present study. The basin has attracted less attention in the past mainly due to its relatively smaller size and proximity to a larger basin. The basin is thought to carry signatures of past seismic activities and falls in the region south of crisscrossing fault zone. Previous studies in this area by Hofmann (1980) have described the quaternary sedimentation. Regional studies by Hodgkinson et al. (2007) focused on drainage patterns and their structural controls.

Digital elevation models (DEM) have been derived from contours at an interval of 5m available from published topographical maps and spot heights from USGS (2004) combined with sedimentological studies of exposed deposits were carried out along the South Pine River.

A fault trending N-S direction parallel to the major fault trend in this area was identified. The surface manifestations of the subsurface structure include a sudden change in the river morphology, change in the slope derived from DEM, confluence of the tributaries on approaching the fault zone and sudden changes in the sedimentary deposits. Alluvial fan deposits were identified on the downthrown block of the fault. Photographs of the sites were taken to record their characteristics. Minor seismic activity has also been recorded close to this fault (one of which was recorded in 1960) confirming its presence.

A combination of changes in lightning, vertical exaggeration and changes in the field of view of the DEM has proved to be very useful in identifying the location of the structure. This fault is thought to be a part of major fault system on the northern part of the study area. The concentration of fault traces decreases significantly from north to south as depicted from studies by Hodgkinson et al. (2007). Further studies, including but not limited to trenching and ground penetrating radar studies can give important clues on the nature and type of the structure.
Can the Unconventional Gas Industry Maintain Their Social Licence?
Authors: Lightfoot Richard
Published: November 2015

The prudent management of resources is a vital part of any company's operation.

Unconventional gas plays place demands on companies as they require the development of safe operations without the loss of a Social Licence.

The accomplishment of a social licence to operate requires corporations to go beyond conforming to legislation and embrace society's needs.

International concern has been voiced about the mature unconventional shale gas exploration and exploitation in North America. This has occurred because of society's lack of understanding of fracking, their perception of the risk and Corporation's lack of engagement.

The oil industry worldwide follows the standards laid down by the American Petroleum Institute (API). These standards have served the oil industry well. However, fulfilment of these standards has not always been achieved by all operators.

Established technology of fracking introduces a sequencing of high pressure cycles into casing and cementing systems in both vertical and horizontal wells. In shale fracking a well is deviated from the vertical to the horizontal. In doing so, will joints in the casing hold under all circumstances; is cement evenly placed between the steel casings and within geological formation? The risk experience in drilling operations is one concern, others include, financial, health, safety and the environment risk is gauged by stakeholders.

The possibility of a methane flow into the aquifer opens the potential of environmental impact on fresh water resources. Methane without adequate capture in populated areas increases the risk to human and animal health. Society has reacted to past failure of mining operations or extractive industries by enacting laws to encourage companies to adopt safer methods of operation.

Consequent on the USA experience, more than nineteen States and Countries have legislated to reverse the burden of proof of liability by enacting a series of bills that form the basis of a ‘Rebuttable Presumption of Liability’.

Corporations must not fail to control operations. They must identify the potential of damage to the environment and human health. Failure to mitigate risks will result in loss of competitiveness, damage to reputation, legal liability arising from failure to abide by regulations and/or private litigation.

The maintenance of a social licence to operate underpins corporate success.
Rock Physics Relationships between Compressional, Shear, and Density Logs in Unconventional Formations, Including Deviated Wells
Authors: Quirein John , Far Mehdi E. , Gu Ming , Gokaraju Deepak , Mekic Natasa
Published: November 2015

This paper compares rock physics trends in the Vp-vs.-Vs crossplot and the Vp/Vs-vs.-compressional slowness crossplot. Trend uncertainties are presented with laboratory data from the Bakken, Bazhenov, Monterey, and Niobrara shales; departures from expected trends attributed to kerogen, hydrocarbon, anisotropy, and well deviation are discussed. Anisotropy models, such as ANNIE (Schoenberg et al.1996), are presented for computing Thomsen parameters and stiffness coefficients.

Castagna mudrock line (Castagna et al. 1993) derived from in-situ sonic and seismic measurements provided an average linear relationship between compressional and shear-wave velocities. Brie (1995) extended previous work to include predicting gas saturation from a Vp/Vs-vs.-compressional slowness crossplot. Projecting the Castagna mudrock line onto a shear-vs.-compressional slowness crossplot proved useful for interpreting sonic data. Classical-rock physics equations were used to model compressional and shear velocities as a function of well deviation. Laboratory anisotropy models allowed for characterizing the effects of dispersion, anisotropy, and well deviation.

Anisotropic-rock physics models for the Bakken, Bazhenov, Monterey, and Niobrara organic shales are presented and compared in terms of the Thomsen parameters, ε, γ, and δ, and stiffness coefficients, Cij. These models are first transposed to trend curves in Vp-vs.-Vs, Vp/Vs-vs.-compressional slowness, and shear-vs.-compressional slowness crossplots and then compared to the Castagna mudrock trend curve. The anisotropy models are then applied to characterize the effect of well deviation on these trend curves. Results are also presented for well log data from the Eagle Ford, Haynesville, and Bakken formations in the context of the discussed crossplots and then compared with the expected trend curves. The Eagle Ford data satisfies the carbonate Vp-vs.-Vs trend predicted in previous literature by Castagna et al. (1993), and the Haynesville data clearly satisfies the gas effect predicted by the Brie Vp/Vs-vs.-compressional slowness crossplot discussed.

In theory, the models describing anisotropy with the Thomsen parameters or stiffness coefficients are equivalent. In practice, not all the parameters for either model can be measured from log data. Preferentially, anisotropic models should be derived by combining log data from multiple vertical, deviated, and horizontal wells for each shale reservoir.
Estimate the Effective Fracture Properties from Tight Formation Production Data
Authors: Tian Wei , Wu Xingru , Zhang Zhenfeng , Ling Kegang
Published: November 2015

Effective fracture properties that contribute to the flow in the tight formations are very important in stimulation job evaluation, productivity estimation, and production forecast. However, there are no direct measurements on the volume of stimulated region or the effective permeability of fracture because hydraulic fractures not only stimulate local matrix, but also connect natural fractures. Therefore, the effective drainage volume contributing to production can be much bigger than the extension of hydraulic fractures.

After a high initial rate, production data for stimulated tight formation has an extended transient flow period in which the matrix functions as a source and behaves in a transient fashion. This behavior can be captured by a dual-porosity model with transient matrix performance under a constant bottom-hole pressure.

This paper studies the problem from an inverse perspective and couples the production data with an interporosity flow model to estimate the effective drainage volume that a well controls as well as the effective permeability that can be used for production rate forecast. The problem is solved in Laplace domain. The proposed model is validated with the numerical simulation and the field production data from Mississippian Lime. Furthermore, the interporosity model is sufficient to forecast the production trend from the given examples.
Slip Velocity and Permeability of Gas Flow in Nanopores for Shale Gas Development
Authors: Okamoto Naoki , Liang Yunfeng , Murata Sumihiko , Matsuoka Toshifumi , Akai Takashi , Takagi Sunao
Published: November 2015

Slip phenomenon is one of major characteristic of gas flow through porous media, of particular in unconventional gas reservoirs with small pore throat, such as tight sands, coal seams, and shale formations. Consequently, a permeability correction needs to be considered for evaluating the flow ability of gas in these reservoirs. There are various analytically derived correction models for engineering applications. However, it is not well understood which one should be implemented in the real problems of shale reservoirs. In this paper, slip velocity and permeability correction for gas flow in nanopores are studied by molecular dynamics simulations. For simplicity, the considered system is methane gas flow in parallel plate channel of quartz. The fluid flow is characterized by the Knudsen number defined as ratio between the mean free path and the representative length of the pores. The studies with various Knudsen number were conducted either by (1) changing the methane density (the mean free path) or (2) plate-spacing (pore size). The simulation results show that the relations between slip velocity (normalized by the maximum velocity) versus Knudsen number and between permeability correction factors versus Knudsen number agree well with Beskok and Karniadakis' analytical solution (BK model) for large nanopores (10-34 nm). This model has considered both rarefaction and compressibility effects to gas microflows and been tested by the experimental results with characteristic dimension of the order of one micrometer. Our simulation results indicate that this model can be further extended to nanoflows as they are in unconventional reservoirs. Some deviations from BK model were noted for small nanopores (2-10 nm), where variance and the apparent gap from BK model became significant. We suggest that the limit for application of BK model may be about 8-10 nm, and it is ascribed to the fact that the overall fluid is no more homogenous (the fluid is structured in the proximity of the walls due to the interaction from the wall molecules).
Simulation of Shale Gas Transport in 3D Complex Nanoscale-Pore Structures Using the Lattice Boltzmann Method
Authors: Ning Yang , He Shuai , Chen Tianluo , Jiang Yang , Qin Guan
Published: November 2015

A shale formation contains numerous organic nano-pores and microscopic fractures, which natural gas flows through during production period. In shale formations, the flow mechanism and the characterization of petrophysical parameters are open and challenging topics for researchers since shale has significantly different characteristics from conventional rocks. Knudsen diffusion is considered as the main flow mechanism in nanoscale pores as the Knudsen number is finite. Many conventional methods have encountered challenges to model natural gas flow in organic nano-pores due to their continuum assumption. The lattice Boltzmann method (LBM) is a good candidate for modelling shale gas flows because it arises from the gas kinetic theory. In this work, three-dimensional (3D) pore structures of a shale core sample are reconstructed based on the Focused Ion Beam Scanning Electron Microscopy (FIB-SEM) technique. The multiple-relaxation-time LBE is used to model gas flows. A slip boundary condition is implemented to capture boundary flows in pores to describe the Klinkenberg effect. In addition, intermolecular forces between pore walls and gas molecules are incorporated to capture the adsorption effects to flow. Methane gas flows driven by gravitational force in square ducts with different sizes have been simulated in order to observe slippage. Permeability of methane gas in 3D complex kerogen pore structures has been investigated. It has been found that the permeability decreases with the pore pressure increases, which follows the Klinkenberg theory.
A New Model to Determine Leakage Factor for a Finite Aquifer Using Pressure Fall off Test in CBM Reservoir
Authors: Wu Xingru , Srivastava Priyank , Escobar Freddy H.
Published: November 2015

Water influx is an important factor which needs to be quantified during early stages of reservoir development to justify project economics. For a CBM reservoir, it is much more important to quantify a degree of connection & boundary between coal reservoir and aquifer (if any) as its production mechanism is based on efficient dewatering process and any communication of coal seams with adjacent aquifer layercan act as a major barrier for development. However, it is difficult to quantify water influx values early in field life as limited data is available from the reservoir; but pressure transient testing, usually done during exploratory stage can play a pivotal part in reservoir characterization. Currently, solutions exist for analyzing pressure falloff test reponses to quantify water influx in the reservoir in communication with an infinite aquifer. However, there can be cases with limited aquifer extent in which case the use of former solution would lead to wrong estimation of water influx communication. So we propose a new model to account for closed outer boundray of aquifer, and use of this model to estimate both aquifer extent and water influx quantification. Leaky aquifer models more accurately describe bottom water drive reservoirs as most of the time aquifer connection with the reservoir is not perfect (ΔPres. ≠ ΔPaquifer). It is extremely important to quantify connectivity between the aquifer and the main reservoir before going for full field development. The method presented in this paper can provide a much needed solution to quantify the aquifer reservoir connectivity and the aquifer extent for a reservoir with bottom water drive earlier in field life using pressure transient data. We demonstrate the robustness of the proposed method using synthetic example for a homogeneous single well radial reservoir.
Flow of Hydrocarbons in Nanocapillary: A Non-Equilibrium Molecular Dynamics Study
Authors: Feng Feng , Akkutlu I. Yucel
Published: November 2015

Unlike flow of fluid in conventional reservoirs, the fluid transport in unconventional reservoirs involves kerogen pore structure with much smaller capillaries. This, in turn, leads to large capillary wall surface area and, consequently, to a significant physical adsorption effect. Measurements are needed to understand the nature of flow inside kerogen structures. However, direct measurements are difficult and have large uncertainties related to kerogen isolation. Non-equilibrium molecular dynamics simulation allow numerical study of fluid transport inside model nano-capillaries representative of kerogen matrices. In this work two different molecular simulation methods are used to study steady-state flow of methane and of methane-butane mixture: External Field Non-Equilibrium Molecular Dynamics (EF- NEMD), the main flow simulation method, and Dual Control Volume Grand Canonical Molecular Dynamics (DCV-GCMD), the simulation method used to verify the results. The flow inside the capillary is simulated under various conditions, e.g., capillary diameter, temperature, average pressure, fluid composition and capillary wall morphology. Based on the simulation results we observe that fluid flow velocity and mass flux are significant near the capillary surfaces where adsorption takes place. Hence, Hagen-Poiseuille equation based on the no-flow condition at the wall significantly under-estimates the fluid flow in nanocapillary. The dependence of surface transport velocity, as well as flow enhancement, are determined quantitatively. The results confirm a previous study by Riewchotisakul and Akkutlu (2015) indicating the presence of a mobile adsorbed-phase in the organic capillaries based on molecular simulation of steady-state methane flow using a moving piston model.
Production Forecasting for Shale Oil: Workflow
Authors: Rincones M. D. , Lee W. J. , Rutledge J. M.
Published: November 2015

Unconventional oil reservoirs have taken a prominent role in the United States as a source of crude oil. Different methodologies to estimate reserves for shale gas and coal bed methane have, thus far, proved to be reliable, but no simple yet accurate workflow has been generally accepted to forecast production and estimate reserves for shale oil. To fill this gap in technology, we proposed and validated a workflow that integrates analytical methods with empirical methods. The final methodology is both easily applied and accurate. In developing the final workflow, we evaluated several alternatives, most of which proved to be unsuitable. We also investigated the use of a filter to eliminate outliers in a systematic way, as proposed by Rastogi (2014).

The workflow was successfully applied to three of four volatile oil wells in the Eagle Ford shale, with similar results. The analytical model that best matched the wells is called the Stimulated Reservoir Volume (SRV) Bounded Model. We tested this and other models using a new field production analysis tool software. While accurate, this modeling approach is too time consuming for routine use. We found that a simple empirical approach that led to the same results as the analytical model was a 3-segment Arps decline model. The early flow regime was transient linear for all the wells; thus an Arps "b" parameter of two was appropriate. When boundary-influenced flow (BIF) appeared later, b-values of 0.2 were found appropriate. The initial decline rate (Di) value during BIF was modified in mid-segment leading to a distinct third segment. Our workflow also led to reliable forecasts of production (to date) of the gas-oil ratio for the three wells.
The Progression of Fracture Stimulations in Horizontal Wells Targeting the Montney Formation in the Heritage Field, British Columbia, Western Canada
Authors: Christie Kyle , Russum Dave , Fitzmaurice Megan , Quinton Aaron
Published: November 2015

Producing unconventional resources through hydraulic fracturing is a continuous learning process where the fracture stimulation design can change throughout the life of the field development. The well completion technique can change because of many reasons such as lessons learned from previous stimulations, new technology, and the heterogeneous nature of the reservoir.

This paper focusses on real world data of hydraulic fracture stimulation properties sourced from public databases which is reported from wells drilled in the Heritage Field near Dawson, British Columbia. These wells are licensed as horizontal wells targeting gas production from the Montney Formation.

By plotting and mapping the fracture stimulation data collected from the area and focusing on a set of operators with major operations in the area, this paper demonstrates how the fracture stimulation has changed over time and illustrates the design changes of the fracture stimulations for each operator over their own development timeline.

This paper also discusses the collaboration initiatives that were implemented as the development progressed to highlight how industry and regulators can work together to responsibly produce the resource most effectively while still maintaining healthy competition.
Investigation of High Resistivities Observed During Azeri-Chirag-Guneshli Oil Field Development
Authors: Aliyarov Rauf , Rzayev Elshan , Ramazanov Rizvan
Published: November 2015

Physical properties of the reservoirs are known to be affected by the dynamic processes dominating during active field depletion. Formation resistivities from the open hole logs are one of the most sensitive measurements influenced by alteration of the reservoir properties due to production. Unusually high resistivity values were noted to occur more frequently with ACG field development. This largely affected water saturation values calculated using Archie model and hence the hydrocarbon volume in place estimates.

Mapping resistivity values across the field revealed the production time dependency of these high readings. A relationship between cumulative oil flux and formation resistivity at irreducible water saturations (away from the water front) was identified based on core experiments from the fields in the similar geological settings and the outputs from the ACG reservoir simulation model. This relationship showed increase of resistivity with the number of pore volumes flushed by oil through the porous medium. Through the systematic analysis of the field data this behavior was determined to be mostly related to the alteration of the wettability as a result of active dynamic processes in the porous medium.
CO2 Emulsified Fracturing Fluid for Unconventional Applications
Authors: AlDuailej Yaser K. , AlOtaibi Fawaz M. , AlKhaldi Mohammed H.
Published: November 2015

The demand for hydraulic fracturing has increased intensely with the transformation from conventional to unconventional reservoirs. High temperatures and extreme depths often amplify the complexity of any fracturing treatment. In addition, the sought synergy between different additives of the fracturing fluid becomes more challenging. As a result, the uncertainty of fracturing performance elevates as these factors become more complicated. Viscosity, propant transport and cleanup are the main criteria for assessing the performance of a fracture fluid. In this study, a fracturing fluid with unconventional composition is evaluated in terms of these parameters for the high temperature applications (300°F).

Most fracturing fluids are mainly composed of water. Since the frequency of fracturing applications is increasing, massive quantities of fresh water are daily consumed in these treatments. Sea-water is an alternative to fresh water; however, it requires accurate and cautious design to prevent incompatibility and instability. Another approach to avoid high water consumption is the use of CO2 emulsified fracturing fluid, where liquid CO2 reaches up to 70 vol%, thus, reducing the need for fresh water. Moreover, CO2 emulsified fracturing fluids offer better cleanup and artificial lift to flow backs.

Series of tests has been conducted to evaluate and optimize a CO2 emulsified fracturing fluid, where liquid CO2 constituted 50-70 vol% of the emulsion. The base gel is non-crosslinked and polysaccharide-based, with environmental friendly properties. The testing was done at different temperatures ranging from 220-300°F. The emulsion of liquid CO2 and base gel generated viscosity values compared to and better than guar-based foamed and gelled fracturing fluids.
Utilization of Single Real Time Data Visualization and Transmission Solution in Oil and Gas Field Development
Authors: Khudiri Musab , Al-Sanie Faisal , Miyajan Ramzi , Wuhaimed Ali , Hawi Maan , Abbas Mazin , Kashif Muhammad , Meraj Hamood , Ahmed Farhan
Published: November 2015

This paper highlights the tremendous impact of real-time data transmission and visualization through the Aramcolink solution for monitoring geosteering operations in Saudi Aramco. It was very challenging to move from multiple real time data providers to a single solution, which can connect with different service providers by utilizing WITSML, which is industry real-time data transmission protocol. Nevertheless, Saudi Aramco has decided to explore this frontier to provide their operational geoscientists/engineers with a single system through which all should be able to simultaneously monitor several actively drilling wells with ease.

Considering the drilling operation in Saudi Arabia, a system with advanced capabilities of data quality control (QC), rescaling, filtering, alerting, and chatting, was essentially required to assist operational geoscientists in optimizing production through geosteering a well by drilling through the sweet zone and achieve good net to gross value. The new solution "Aramcolink" is not only limited to these capabilities but distinguishes itself among other rival solutions by unmatched features such as data cross-plotting, on the fly azimuthal image dip calculation, built in petrophysical analysis and electrofacies computation, 2D and 3D well trajectory visualization, and others.

Moreover, information is now provided on how using such an approach helped in enforcing Saudi Aramco's standard for real-time log naming, measurement unit, and scaling, thereby facilitating more automated operational workflows. The paper concludes by sharing lessons learned and recommendations for future improvements.
Enhanced Core Analysis Workflow for the Geomechanical Characterization of Reservoirs in a Giant Offshore Field, Abu dhabi
Authors: Noufal Abdelwahab , Germay Christophe , Lhomme Tanguy , Hegazy Gehad , Richard Thomas
Published: November 2015

This paper is focused on the integration of two laboratory centimeter-resolution logs of mechanical properties (strength and compressional elastic-wave velocity Vp) into an enhanced core analysis workflow for the geomechanical characterization of unconventional reservoirs in a giant field in Abu Dhabi, where fracking is the cornerstone for producing the unconventional oil. The design and placement of hydraulic fratures rely strongly on the a-priori knowledge of the stress profile and brittleness index, which were estimated via a mechanical earth model constructed from wireline logs and correlations based on US shales analogues. With most of the stratigraphic column in the Abu Dhabi field composed of carbonates, the calibration of the mechanical earth models was found critical as the US shales based correlations would otherwise not have been suitable to the geomechanical characterization of these tight carbonate reservoirs.

With this case study we illustrate:How the combination of the continuous profiles of rock strength UCS (Uniaxial compressive strength) and P-wave velocity measured directly on dry cores with the scratch tests contributes to the identification of different Geomechanical Facies,How the mapping of several Geomechanical Facies enables the building of a simple yet robust relationship between the UCS measured directly on cores and properties such as the total porosity and acoustic velocities of sonic waves, obtained from wireline logs, andHow the centimeter-resolution profiles of strength and elastic wave velocities measured on dry cores enable the proper upscaling of geomechanical properties measured on plug samples to the entire cored section and the computation of a horizontal stress and brittleness profiles derived from unbiased geomechanical properties.

From this case study follows a general discussion on the relevance of wireline sonic logs relative to centimetric resolution data (scratch profiles or plug measurement) acquired on dry cores for the geomechanical characterization of reservoirs. We conclude that measurements on dry cores enable the more robust calibration of mechanical earth model and in turn better description of the reservoir mechanical response. The upscaled profiles of horizontal stress and brittleness index derived from dry core measurements would ultimately lead to an alternative strategy for the design and placement of hydraulic fractures along producing wells.
Polymer-Based Scale Inhibitors for Seawater Injection Operations in High-Salinity Formation Water Reservoirs
Authors: Obied Marwa A. , Alkhaldi Mohammed H. , Mubarak Tariq A. , Yami Ibrahim S. , Sahman Faisal M.
Published: November 2015

Water flooding using seawater is a major oil filed operation implemented in different carbonate and sandstone reservoirs to maintain reservoir pressure and enhance oil recovery. However, due to the high sulfate content in the injected seawater, significant calcium, barium and strontium sulfate scale deposition can occur and cause severe formation damage. Typically, scale inhibitors are applied in the field to prevent the formation of calcium sulfate scale where they act either as chelating agents to form a soluble complex, as threshold inhibitors, which block the development of the supercritical nuclei or as retarders of the growth of the calcium sulfate crystals. The objective of this study is to evaluate the effectiveness of different types of scale inhibitors to prevent the formation of calcium sulfate scale during the injection of seawater into high-salinity bearing carbonate reservoirs.

Jar testing and SoftPitzerTM software were used to investigate the calcium sulfate precipitation due to the mixing of high calcium-content (37,000 mg/L) formation water and high sulfate-content (4,000 mg/L) seawater. This investigation was conducted on different mixtures of formation water and seawater at reservoir temperature of 155°F. Different types of scale inhibitors were tested to prevent the scaling of calcium sulfate in mixtures of seawater and formation water. The compatibility of these scale inhibitors with calcium ions present in formation water and also their effectiveness in preventing CaSO4 scaling were investigated using bottle testing. In addition, coreflood experiments were conducted to determine the adsorption behavior of these inhibitors in carbonate rocks.

Results showed that the application of two scale inhibitors (Acrylic homopolymer-based) can successfully mitigate calcium sulfate scale formation in seawater/formation water mixtures up to 155°F. Each one of these two scale inhibitors has its own effective minimum inhibition concentration (MIC). In addition to these results, the paper provides insights into the adsorption behavior of these inhibitors in carbonate rocks and how this affects their performance.
SCAL with Full Hysteresis Significantly Impact Giant Carbonate Reservoir Performance and Improve The History Match Quality Case Study
Authors: Ismail Ahmed M. , Jasser Majdolin Hanna , Hafez Hafez H. , Zubair Kalam Mohamed
Published: November 2015

Numerical reservoir simulation model of a giant carbonate reservoir with thick transition zone has been built and the saturation functions have been generated and tested with different Hysteresis options during full field history match process. In this super giant carbonate reservoir with multi-million active cells and twelve reservoir rock-types, running the full hysteresis option proved prohibitive due to excessive run times, and in many cases the run fails. Therefore scanning curves have been generated using algorithms to mimic the hysteresis option. This paper aims at presenting the impact of using water-oil capillary pressure and relative permeability full Hysteresis for mixed wet super-giant carbonate reservoir on the full field history match results of water flood and development plan for EOR as well as optimizing the 3D simulation run time. Different models were tested including Corey model, modified Corey, and Killough Hysteresis model to develop appropriate bounding and scanning curves. Sector model was built to ensure reliable scanning curves from each model, and the resulting scanning curves from this sector model compared with the mathematical approach used to generate scanning curves over a wide range of water saturation.

Several sensitivities on SCAL Hysteresis option have been made to improve the match quality of the water saturation changes, breakthrough time and production & pressure performance on field and individual wells level (i.e. No Hysteresis, both Kro & Krw Hysteresis, only Kro Hysteresis, full Hysteresis Kr & Pc…. etc.).

Using full Hysteresis saturation function curves show significant impact in the history match quality especially in transition zone where it was difficult to match the flood front with the normal saturation function. It worth mentioning that using scanning curves (121 curves was the optimum number of scanning curves) showed reduction in the simulation run times compared with the full hysteresis option.
Improved Hydrocarbon Recovery of a Lean Retrograde Gas Reservoir Under Propane Injection
Authors: Md Yusof Muhammad Aslam , Fuad Iqmal Irsyad , Matali Awangku Alizul
Published: November 2015

In most cases, retrograde gas reservoir in N Field which is located at the north of Malay Basin achieved 40-70% of recovery factor (RF) compared to dry gas reservoir, 80-90% of RF. Reservoir K, a lean retrograde gas reservoir of the N Field drained by Well 5 experience reduction in recovery (about 15% of RF) that is caused by a significant productivity loss, because of condensate banking. Condensate banking phenomenon (observed as skin) around the perforation zone restricted the flow of gas after the flowing bottom hole pressure falls below the dew point pressure. Therefore, the reduction in gas Inflow Performance Relationship (IPR) limits the Estimated Ultimate Recovery (EUR) of Reservoir K. It is the focus in this project to analyse the effect of miscible propane stimulated injection on the IPR, well deliverability and hence reservoir recovery. The retrograde gas reservoir model is integrated between E300, IPM PROSPER (well model) and IPM MBAL (reservoir model) software in reservoir performance prediction and forecasting study. Results show that there is 4% increment in gas recovery and 6% increment in condensate recovery after injection of propane to Reservoir K. There are about 4.2 million USD increment in revenue upon propane injection development. As conclusion, it is found that propane injection could minimize the condensate saturation that improves reservoir IPR and hydrocarbon recovery for both gas and condensate.
Knowledge Management in Multigenerational UAE Workplaces: Learning-Training Preferences and Knowledge Transfer Barriers
Authors: Lim Hwee Ling
Published: November 2015

Companies in the United Arab Emirates (UAE) need to understand generational differences in teaching-learning preferences so that vital job skills held by older employees are transferred successfully to younger workers. Hence, this study compared the preferred teaching-learning methods for technical skills between generations and identified the main barriers to knowledge transfer experienced in the UAE work context. Interviews were conducted with 85 supervisors and 91 supervisees from three generations (Boomers, Generations X and Y), comprising Emiratis and UAE expatriates. It found that on the job training and one-on-one coaching with a mentor were younger supervisees' most preferred methods for learning technical work skills that corresponded to teaching methods used most often by older supervisors. However, assessment/testing and feedback was a less preferred learning method yet experienced more at work by supervisees. While individual and organizational structure barriers were experienced in knowledge transfer processes, the former was predominant. Older supervisors attributed difficulties in transferring knowledge to supervisees' lack of motivation to learn and poor communication skills while main barriers experienced by younger supervisees were supervisors' sense of job insecurity and poor communication skills. The results highlighted difficulties in cross-generational knowledge transfer processes that stem from preferences in teaching-learning methods and individual factors. These findings could guide organizations in designing knowledge transfer mechanisms that ensure both employees and knowledge are used to their fullest potential.
ADGAS LNG Train-3 APC Implementation
Authors: Raghuraman S. N. , Dabak Abhay
Published: November 2015

ADGAS implemented Advanced Process Control Solution (APC) for LNG Plant with intent to Increase throughput while respecting all the constraints required for ensuring integrity and reliability of its assets. It is also helping us to improve efficiency, reduce emissions and also to reduce operator stress by substantially reducing operator interventions required.

Model based predictive control is used in implementation of APC. Overall structure of controller includes 5 controllers which are optimized by overall controller using QP technique.

This types of implementation is not so uncommon in industry today, however, at ADGAS we had some peculiar challenges which were eventually overcome using innovative solutions

MR Composition Control MR Optimization Need for Robust Inferential structure Tackle impact of gas drier change over on upstream and downstream plant
First Application of Thermal Activated Resin as Unconventional LCM in the Middle East
Authors: Knudsen K. , Leon G. A. , Sanabria A. E. , Ansari A. , Pino R. M.
Published: November 2015

One of the major challenges when drilling gas wells in offshore fields is to drill under high pressure and in a loss circulation zone in intermediate hole sections. Heavy mud is used to control the pore pressure in a narrow operational window that creates losses and, as a consequence, well control issues. Several solutions/ideas have been implemented while drilling this intermediate section, including a thermal-activated resin, rigid rapid fluid treatment, used to regain full circulation and successfully increase the window gradient.

The solution to these challenges was developed by designing a fast setting, thermal-activated resin LCM liquid plug with a density equal to 152 pcf. This new treatment slurry was able to be bullheaded and displaced with a polymer mud 152 pcf. The slurry was easily pumped through drill pipe, measurement while drilling (MWD) and drill bits.

This paper presents case histories and field applications of this novel polymer-based lost circulation material, for successful treatment of heavy mud losses to formation in wells in offshore gas fields in the Middle East. The paper also includes a discussion of the methodology, material properties and applications.
Possibility of Nanofluid/Gas Alternating Injection as an EOR Method in an Oil Field
Authors: Al Matroushi M. , Pourafshary P. , Al Wahaibi Y.
Published: November 2015

Water flooding and gas injection are the most commonly used EOR methods. Due to the viscous fingering, reduction of sweep efficiency and early breakthrough of the injected fluid, the performance of these methods are not appropriate. Hence, water alternating gas approach (WAG) is applied to solve the unfavorable mobility ratio and enhance the fluid contact in the reservoir by segregating gas to the top and accumulating of water toward the bottom.

Through the past years, several experimental works have been done to prove the ability of nanoparticles to increase the oil recovery efficiently. Presence of nanoparticles in water alternating gas (NWAG) is a novel method of enhanced oil recovery in intermediate and oil-wet reservoirs. This novel method results in economic and efficient oil recovery by combining improved macroscopic and microscopic sweep efficiencies. Nanoparticles sit on the rock surface and alter the wettability of the rock. Also, nanoparticles locate in oil/water interface and reduce the interfacial tension. These mechanisms modify oil properties and mobilize trapped oil in the reservoirs.

This research project aims to study the effects of the nanoparticles on the wettability alteration, relative permeability curves, and IFT changes during Nanofluid alternating gas approach (NWAG) by modeling the fluid/rock interactions during coreflooding experiments. Moreover, the possibility of using this approach as an EOR method in the field scale was investigated. Our results showed a good history match for oil recovery obtained from coreflooding experiment for WAG and NWAG injections with less than 10% error between the model and the lab data. Our simulation showed that application of nanofluid instead of water during WAG process shifts the wettability of the system toward more water wet which affects the relative permeability curves and enhances the recovery. For example application of NWAG in 6 months’ time cycle with 5 months nanofluid and 1 month CO2 injection period in 2:1 NWAG ratio with Dual Five-spot well pattern improves the oil recovery for 13% compared to the conventional WAG method.
A Systematic Integrated Approach to Evaluate Artificial Lift Requirements While Dealing With High Uncertainty
Authors: Caicedo S. , Montoya C. , Abboud J. , Tiar S.
Published: November 2015

When evaluating artificial lift requirements, sometimes data present uncertainties at the initial planning stage, which could be related to reservoir complexity, poorly defined reservoir development plans etc. This is the case for a field that had ten wells drilled and only four of them producing after 6 years when operations were suspended. The high level plan was to exploit and abandon the reservoir as soon as possible taking into consideration the HSE regulations for this urban area.

In addition, there were major challenges associated with this development: adjusted timeline, high H2S and CO2 concentrations and fluid processing facilities located 45 km away that necessitates a high transfer line export pressure. The data and studies initially available required revision to understand the reservoir and the production history and to have a suitable and more reliable model to predict the well production profiles. Typically, an artificial lift evaluation stage comes after the reservoir has a good model and a defined exploitation scheme. In contrast, in this case, the selection of the artificial lift method dealt with high data uncertainty associated with: the reservoir pressure, GOR and water cut time profiles as a result of the reservoir's complexity and PVT properties.

To overcome this situation and advance quickly a novel matrix approach was adopted, which focused on the following: To understand and demonstrate how uncertainty affects artificial lift selection;To perform a preliminary Artificial Lift method screening covering the uncertainties in order to discard some methods and focus on possible solutions;To use the matrix to determine the envelopes when wells can flow naturally and when artificial lift is required;To determine the probability of the scenarios in relation to the results of an ongoing reservoir simulation that would be available at later stage.

The present paper shows how an integrative and structured methodology can deal with high uncertainty conditions in a real case.

The approach used suggests how to discard artificial lift options using constrains while focusing in the real options and evaluating the possible outputs and conditions for the worst case scenarios based on the expected wide ranges.
Production Optimization Strategy Using Hybrid Genetic Algorithm
Authors: Salam Damian Dion , Gunardi Irwan , Yasutra Amega
Published: November 2015

Optimizing production is no longer an option, nowadays, it is a necessity. The wells have to produce longer and better than ever before in order to influence projects attractiveness. However, the process to define variables such as well placement, number and type of wells, well production and injection scheduling, and operational conditions is time-consuming and demands high computational effort. Therefore, the objective of this research is to provide an optimization algorithm resulting good solution efficiently.

The optimization algorithm used in this work is the hybrid genetic algorithm (HGA) which is the combination of GA with artificial neural networks (ANN) and evolution strategies (ES). This HGA attempts to simplify the complex and diverse parameters governing the production optimization problem. The HGA is coupled with commercial simulator and has been applied in real fields to quantify the benefits of this HGA over a base case with the conventional one. Additionally, it is proposed to minimize the number of combinations of possible solutions that makes the optimization algorithm becomes simply elegant by performing the process efficiently and effectively.

The HGA proposed in this study is used to optimize the production strategies in realistic reservoir models, defining the number, type, and position of production and injection wells, and also the production or injection flow rates. Therefore, the HGA is proved to be suitable for any kind of reservoir models. Moreover, the number of individuals in a population, the number of generations, and the genetic parameters are varied and adapted by applying ANN and ES to evaluate the efficiency of the algorithm. From this study, an optimization algorithm in production strategy is provided. Results showing the performance of several optimization processes are presented in this work. The analysis and comparison regarding the genetic parameters are presented. Moreover, the proposed HGA is proved to be time-saving and operation-efficient, plus it provides an optimized solution.

Based on the fact that every well is a new challenge that defines a single-solution approach which results the production optimization strategy becoming more and more complicated, the use of an optimization algorithm to achieve a good solution can be very valuable to the process, yet it can also lead to an exhaustive search, demanding a great number of simulations to test many possibilities. This novel HGA is presented to tackle and handle those issues.