bluuebunny/crossref_metadata_2025 huggingface dataset:
Model Fracture Formation in Mechanical Layers During Basin Burial Effects of Mechanical Properties Stress Fields Pore-Pressure and Layer Thickness
Authors: Fukunari T. , Gudmundsson A.
Published: November 2016

The aim of this paper is to provide analytical solutions of stress fields in mechanical layers which consist of stiff and soft or compliant layers. The paper examines possible geological conditions of mode I (extension) fracture development on the basis of the analytical calculations with various layer thicknesses, Young's moduli, Poisson's ratios, external stress fields and pore-fluid pressure. Linear elastic model with two different mechanical layers is assumed for the calculations. Fluid-driven fractures, hydrofractures, are discussed in detail elsewhere and are not considered here. Layer-parallel stresses in the model caused by external stresses and pore-fluid pressure are mathematically calculated for both stiff and soft layers. Relative Young's modulus and relative thickness between the two types of layers are applied to simplify the associated equations. Poisson's ratio v is assumed to be same between the two. This is because the possible variation of Poisson's ratio between rocks is much smaller than those of the other parameters. The calculated ratio of minimum to maximum principal stresses within each layer is used to estimate fracture type which can develop under various geological conditions. The results indicate extension fracture preferably develop in stiff layer. Stress conditions in the model are primarily controlled by relationship among external horizontal stress σXX, vertical stress σZZ and pore-fluid pressure Pf: no tensile fracture forms when σXX > Pf + v(σZZ - Pf)/(1 - v); tensile fractures can form only in stiff layers in soft-layer-dominant system when Pf + v(σZZ - Pf)/(1 - v) > σXX > Pf; tensile fractures form in stiff layers in both stiff-layer-dominant and soft-layer-dominant systems when Pf > σXX > 4Pf/3 - σZZ/3; tensile fracture can form in both stiff and soft layers in soft-layer-dominant formation with small relative Young's modulus when 4Pf/3 - σZZ/3 > σXX. Only shear fractures can form in soft layers, except the rare geological condition of 4Pf/3 - σZZ/3 > σXX with very small relative Young's modulus. The results of analytical calculations provide potential criterion to estimate when and where layer-scale extension fracture network develops in relation with geological history. One implication of the results is that extension fracture formation is not necessarily related to regional tensile stress field but ratio among horizontal stress, vertical stress and pore-fluid pressure. This implies that extension fracture network can form in mechanical layers not only during crustal uplift/exhumation but also during basin-burial in which horizontal stress, vertical stress and pore-fluid pressure are increasing.
Screening of Nanoparticles to Control Clay Swelling in Coal Bed Methane Wells
Authors: Patel Archana , Goh Clarice , Towler Brian , Rudolph Victor , Rufford Thomas E.
Published: November 2016

The swelling of smectite clays in the interburden rock layers of coal seam gas wells results in spalling of fine particles that may negatively impact gas production through damage to the well's pump and/or the permeability of the coal layers. One of the causes of the clay swelling is the change in water chemistry at the wellbore location due to drilling fluids and the influx of produced water. The conventional technology to mitigate the swelling of smectite clays in oil and gas reservoirs is to stabilize the clay using a brine such as 4 % KCl, and although this technology is relatively low cost and initially effective the mitigation of clay swelling is temporary because K+ ions are easily washed from the clay when the well is brought into production. An alternative approach recently reported is to use nanoparticles and nanofluids to control clay swelling.

In this laboratory study we evaluated the effectiveness of five commercially available nanoparticles – SiO2, Al2O3, ZnO, Fe2O3, and ZrO2 – to prevent swelling of a natural bentonite clay that was rich in sodium montmorillonite. The effectiveness of the nanoparticles to prevent clay swelling was measured with a visual swelling index method based on ASTM D5890-11 and compared to the swelling of the clay in 4 % KCl brine. In the initial nanoparticle screening tests performed in distilled water all the nanoparticles except for the ZnO exhibited some potential to mitigate the swelling of bentonite. The next stage of screening experiments was performed in model formation water solutions containing 2500 mg /L and 9000 mg/L of Na ions at pHs of 5 and 9. In the model formation water tests, the SiO2 was the most effective nanoparticle to mitigate clay swelling across the range of conditions examined.

These experimental results suggest nanoparticles may be a potential solution to mitigate clay swelling and spalling in coal seam gas reservoirs as well as other types of reservoirs. Further research is required to elucidate the mechanism of swelling inhibition with SiO2 nanoparticles and to develop practical methods to deploy nanoparticles into a CSG well.
A Comprehensive Approach for the Development of New Magnetite Nanoparticles Giving Smart Drilling Fluids with Superior Properties for HP/HT Applications
Authors: Vryzas Z. , Zaspalis V. , Nalbantian L. , Mahmoud O. , Nasr-El-Din H. A. , Kelessidis V. C.
Published: November 2016

Commercial hematite (Fe2O3) and magnetite (Fe3O4) nanoparticles (NPs) had been used as additives to develop smart drilling fluids. Both types of NPs were found to enhance the properties of such fluids. This work focuses on using a custom-made (CM) magnetite (Fe3O4) NPs to improve the properties of bentonite-based fluids. The microstructure qualities and mode of interaction have indentified, which help in optimizing the rheological and fluid loss properties of drilling fluids.

Rheological properties of the tested fluids were measured using a rotational viscometer at different temperatures up to 60°C (140°F) and atmospheric pressure. Step-change shear rate measurements revealed the degree of thixotropy of the produced suspensions. Fluid loss characteristics were examined under 20.7 bar (300 psi) and 121°C (250°F). Both rheological and fluid loss measurements were also conducted using fluids that are thermally aged at 177°C (350°F) for 16 hrs. Filter cake surface morphology was evaluated using scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS). Bentonite composition was examined by X-ray diffraction (XRD) and X-ray fluorescence (XRF). A superconducting quantum interference device (SQUID) magnetometer was used to measure the magnetic properties of the CM Fe3O4 NPs, and their size was determined using transmission electron microscopy (TEM).

The CM Fe3O4 NPs, which were synthesized by co-precipitation method, have average diameter of 6-8 nm, as indicated by TEM. Magnetic measurements revealed their superparamagnetic behaviour with saturation magnetization of 60 emu/g. For all the tested samples, the Herschel-Bulkley (HB) model was determined to be the best fit model with good correlation coefficient (R2 > 0.99). Yield stress, viscosity, and gel strength of the tested fluids showed significant improvement when adding the CM Fe3O4NPs, which could be a result of the rigid network formed. A linear dependence of yield stress on temperature of the produced nanofluids (NF) was identified. Adding the CM Fe3O4 NPs at 0.5 wt% showed optimal rheological and filtration characteristics. Dynamic thermal aging adversely affects the properties of base fluid. However, the NF maintained its extraordinary rheological and filtration behavior. SEM-EDS analysis revealed the microstructure of the produced filter cake.

The better performance of the CM Fe3O4 NPs can be attributed to their extremely small size, which confer stability in suspensions and effective linking with the bentonite particles, thus allowing the formation of a rigid microstructure network. Such approach introduces the synergistic interaction of components to produce a water-based drilling fluid system with excellent fluid loss characteristics and optimal rheological properties for HP/HT applicaltions.
Novel Coiled Tubing Perforation Approach Enables Efficient Multistage Hydraulic Fracturing Operations in a Horizontal Well in Oman
Authors: Al-Ghaithi Ali , Alawi Fahad , Sayapov Ernest , Ibrahim Ehab , Aouchar Najet , Jumaat Shafie
Published: November 2016

The global horizontal well fracturing market has grown tremendously in the last decade with the increase of multistage fracturing operations. Many of these wells are cased and cemented and had a sequence of a plug and a series of perforations for each stage of the fracturing process. Intervention optimization became a key element for work efficiency and thus cost reduction. A common approach worldwide is to pump-down the plug combined with a few guns and initiate the firing downhole sequentially using switches. Despite the efficiency of this technique, it requires an overflush after each fracturing stage to clean the wellbore of leftover proppant and allow free passage of the plug and guns to be pumped down. Unfortunately, overflushing hampers the fracture's performance because it allows the fracture to close near the perforations. This effect on productivity is now being realized on these overflushed wells, although these wells were once constructed very efficiently.

To move away from overflushing, some operators switched from pump-down to coiled tubing (CT) conveyance of the multiple guns. Conventional CT or CT with electric wireline were used, and each technique has its own advantages and limitations. A newer technology is CT equipped with fiber optics in combination with an optic-based selective perforating system that enables the firing of multiple guns in a single run. This technology combines the advantages of both the conventional CT and the CT equipped with wireline cable. Equipped with gauges, the CT equipped with fiber optics also permits better acquisition of fracture data in horizontal wells. The result is a more efficient operation, better fracture evaluation, and well productivity enhancement by avoiding the damaging effect of overflushing.

After an evaluation of current conveyance techniques, an implementation trial of the new technology on multiple fracturing stages was performed in a horizontal well in Oman. The first trial showed successful application of the technique, especially the accurate real-time gamma ray and casing collar locator (GR-CCL) correlation of the multiple short guns. Even more important was the successful placement of the proppant into the formation during the hydraulic fracturing process. The technique was shown to be efficient while mitigating the possible damage to the formation.
Development of New Formulation of Geopolymer Cement for Oil Well Cementing
Authors: Suppiah Raja Rajeswary , Rahman Siti Humairah Abd , Irawan Sonny , Shafiq Nasir
Published: November 2016

In this paper, we report the results of the investigations on the effects of sodium hydroxide (NaOH) concentration and different ratio of silicate to hydroxide on the density, rheology and compressive strength of geopolymer cement system used in oil well. Different ratios of Class F fly ash is mixed with different ratios of sodium silicate to sodium hydroxide ratio (2.5, 1, 0.5 and 0.25) to produce different geopolymer slurry densities and dispersant is added to control the rheological properties of the system. The NaOH solution was prepared by diluting NaOH pellets with distilled water according to the specified molarity (8, 10, 12 and 14 M). The solution was then mixed with sodium silicate to form the alkaline solution. Class F fly ash were added to the reactive to form homogeneous mixture, which was tested for its density and rheological properties at surface temperature. The mixture was placed in a 50 mm mould and cured at 930C and 3000 psia for 24 hours and the cubes were tested for destructive compressive strength. The results showed that as the concentration of sodium hydroxide increases, the density of the geopolymer cement increases. There was no significant variation on the density of the geopolymer cement. Also, as the ratio of silicate/hydroxide increases, the viscosity of the slurry increases and the workability of the geopolymer cement become poorer. Furthermore, the compressive strength increases as the NaOH molarity increases however when it reaches 14M, the adverse effect to the strength development was observed.
Real-Time Directional Survey Quality Improvement Using Web-Based Technologies
Authors: Maus Stefan , DeVerse Shawn
Published: November 2016

Optimal wellbore placement and collision avoidance requires accurate real-time steering of directional wells. Uncertainties in the wellbore position are accounted for by industry standard error models. However, these error models are only valid if the directional surveys are quality controlled and gross error is prevented by appropriate procedures. Particularly effective quality control is achieved by independent validation. A novel real-time web application was developed for the transfer of directional survey data between the rig site and a remote operations center. Surveying professionals at the rig site upload or import survey data into the web application in real-time. The survey measurements are then automatically validated through independent quality checks to identify gross error. Remote survey analysts can access the pre-qualified survey data and evaluate it for systematic or random error that would indicate non-compliance with the instrument performance model. Surveys can also be corrected in real-time when systematic error is identified and provided back to the rig site personnel for accurate steering and wellbore placement. This web service has been implemented and refined on over 50 rigs in North America. Examples for common types of errors that were prevented and/or corrected are incorrect magnetic declination, wrong north reference, excessive drillstring interference, poor instrument calibration, sensors misaligned with the wellbore and incorrect survey order. The impact of these errors if not prevented could easily cause 100 ft. or more in positional error at the bottom hole location. Real-time survey quality analysis provides higher confidence in wellbore placement, reduces risk of collision, and maximizes reservoir drainage.
Brittleness Index Prediction From Conventional Well Logs in Unconventional Reservoirs Using Artificial Intelligence
Authors: Shi Xian , Liu Gang , Jiang Shu , Chen Lei , Yang Liu
Published: November 2016

Brittleness index is one of the critical geomechanical properties of reservoir rocks. In fact, it is not possible to have accurate solutions to evaluate hydraulic fracturing effectiveness without having accurate brittleness value. Different methods were proposed to measure this parameter, which some of them need reservoir geomechanical parameters by tri-axil experiments, and some others such as mineral analysis are very expensive. Elastic based brittleness is commonly applied because it can provide continuous profile but S wave is generally not performed in all wells. Therefore, attempts have usually been carried out to use artificial intelligences for identification of the relationship between the well log data and core mineralogy based brittleness. This study proposed a new approach based on two common neural network approaches by conventional logging data. The mineral based brittleness database from one well in Jiaoshiba shale gas filed, China were established through QEMSCAN and X-ray diffraction (XRD) analysis. Construction of back propagation artificial neural network (BPANN) and least squares support vector regression (LS-SVR) for predicting formation brittleness is described. Moreover, an overall ranking of sensitivity degree is then provided to show the impacts of different well logs as inputs on models. Obtained results of both LS-SVR and BPANN model are competent for predicating brittleness. But, LS-SVR approach is more accurate than the BPANN method at same conditions. These artificial intelligence methods are first adopted in formation brittleness prediction and the integration of core mineralogy based brittleness and well logs is more practical and applicable than elasticity-based brittleness method using acoustic full waveform logging.
Reducing Drilling Operational Risk and Non-Productive Time Using Real-Time Geomechanics Surveillance
Authors: Hamid Osman , Khan Khaqan , Rahim Zillur , Omair Ahmed , Ahmed Sajjad , Ahmed Mujahid
Published: November 2016

Mud weight optimization is a key driver in attaining optimum wellbore stability while drilling horizontal wells. This paper demonstrates the role of geomechanical knowledge prior to and while drilling to address wellbore stability related issues to help reduce drilling risk and non-productive time (NPT).

To maximize gas production from a tight carbonate reservoir, horizontal drilling and multistage hydraulic fracturing methods have been adopted. For several wells, maintaining wellbore stability has been a challenge without prior geomechanical knowledge of the field resulting in undesired drilling events such as tight hole excessive reaming, stuck pipe, and difficulties while making trips. Even in wells with pre-drill geomechanical analysis for mud weight recommendations, uncertainty in the pore pressure due to depletion along the horizontal section of the wellbore, drilling with one recommended single mud weight (MW) posed great challenge to manage wellbore stability.

In this paper, statistical analysis of data is used to investigate root causes of wellbore stability related issues for a number of horizontal wells drilled in the direction of the minimum horizontal stress. The analysis suggests that wells drilled with little understanding of geomechanical properties along the wellbore path encountered significant NPT's compared to those wells where understanding of rock mechanical behavior and in-situ stresses was utilized to make recommendations prior to drilling. In some cases it helped reduce NPT to less than 2% even in exploration wells.

Among the successful wells, results from a case study describing the real-time (RT) geomechanics workflow was used to optimize MW enabling drilling the well to the planned target depth. The uncertainty related to pore pressure and intervals of high porosity which creates a significant risk of differential sticking were addressed by incorporating RT data and updating wellbore stability models and providing recommendation to the field operation. The paper demonstrates the role of geomechanics and its impact to drilling operations aimed to reduce operation cost and increase drilling efficiency by eliminating geomechanics-related wellbore stability problems.
Recovery of Transport and Geometrical Properties of a Hydrocarbon Reservoir by Statistical Analysis of Microtomographic Images of Core Samples
Authors: Bazaikin Y. , Gurevich B. , Lebedev M. , Khachkova T. , Kolyukhin D. , Lisitsa V. , Tcheverda V. , Merzlikina A.
Published: November 2016

Due to the apparatus restrictions the resolution of the micro-CT scans of rock samples and the size of the 3D image are strictly connected. Thus improve in the resolution giving more detailed representation of the rock structure reduce the size of the sample, so that it goes below the representative volume for the estimation of a particular property. In this paper we study four 3D images of different resolution of Bentheimer sandstone. We show that the geometrical and statistical properties of the images (pore-to-core distribution, porosity, specific surface area, topology) can be stably reconstructed from the images of about 100 voxels. However, numerical estimation of the physical properties, such as permeability, requires larger images. To overcome this difficulty we suggest using statistical simulation of the sampels, based on the stably recovered information – image properties. In this paper we considered the simplest method of statistical simulation; i.e. truncated Gaussiam technique, which is based on the information about the total porosity and correlation length of pore-to-core distribution. This approach underestimates the specific surface area of the pore space, but the permeability of the sample was matched accurately.
Extracting the Best Value from Mature Fields by Petroleum Geoengineering
Authors: Yin K. Yin , Masoudi R. , Rajput S. , Kandau Flavia , Amat Hadi B. , Ring M. , Bertoldi Luca , Ismail S.
Published: November 2016

The success of extracting the best value from mature heterogeneous fields to meet global energy challenges is directly linked to innovation and creativity. The development of these fields requires optimized economic models and fit for purpose reservoir depletion strategies. Petroleum geoengineering is the answer to evaluating remaining opportunities and managing the key uncertainties using smart technologies and reducing the risk of development. This paper describes the field example of how a petroleum geoengineering based approach can optimize the fast track development of a marginal fault block within a complex oil field which is located in offshore Sarawak Malaysia.

The advantages of this workflow compared to the conventional field development plan (FDP) approach is that the iterative time consumed in matching the dynamic model and adjusting the geological model has been properly managed. In our case study, this workflow has improved the quality of the technical proposal as well as saving project duration significantly. In accordance to the workflow, the reservoir architecture was interpreted based on seismic interpretation, geological and reservoir performance understanding. Seismic Inversion derived geobodies were then identified as development targets. Better delineation of the main geological features was achieved using a seismic inversion based algorithm. By prioritizing data consistency among geoscientists, geomodellers and reservoir engineers, a fast track field development plan was developed within manageable uncertainties. Greater reliability of inversion results help to avoid perpetuating bias tendencies on data used for model calibration or quality check.

The petroleum geoengineering based study for such oil reservoir shows how an integrated approach enabled time saving for subsurface development concept identification covering range of estimated hydrocarbon volumes. As a result of geoengineering approach in marginal fault block, the technical proposal was completed within 8 months duration.
Application of Geomechanics for Tight Oil Reservoir Characterisation and Field Development
Authors: Kiatrabile T. , Noosri R. , Hamdan M. K. , Kusolsong S. , Palviriyachote S. , Suwatjanapornphong S. , Rattanarujikorn Y. , Sarisittitham S. , Piyajunya T. , Phonphetrassameekul N. , Manai T. , Adisornsupawat K. , Mustapha H. , Press D.
Published: November 2016

The main objective of this paper is to present the assessment and methodology that would improve the tight oil recovery by hydraulic fracturing (HF) wells. The methodology is enabled by a fully integrated workflow orchestrating petro-physical log interpretation, static modelling, and dynamic modelling coupled with rock mechanics for an optimal fracturing design and mitigating the underlying risks.

In the past, well placement in tight reservoirs and HF design were performed mostly based on available analogous data of offset wells using rock mechanics parameters such as stress magnitude and regional stress orientation to predict the fractures that would propagate through the reservoir in a certain location and well orientation, the stress/strain regime is one of the key parameters that plays an important role. It is also the key performance indicator for developing the tight oil reservoir with underlying complexities.

The process is initiated by the conventional static modelling which involves structural framework construction, distributing the petro-physical characteristics subject to the well logs and other available subsurface data. The second step is to perform a history match of a derived dynamic model by honouring the observed data. This process helps in calibrating the model to be able to represent reservoir dynamic behavior. The results of the history matched model; i.e., reservoir pressure through time is the key input for the Mechanical Earth Model (MEM) in the next step. The MEM process starts with the construction of a 1D MEM using well log advanced scanner and rock mechanics properties from laboratory to represent the strength and elastic properties of the rock where existing wells have been penetrated into the reservoir layers. Hence, a coupled dynamic reservoir simulation with 3D geomechanical model will yield a realistic relationship between the current reservoir depletion state in terms of pressure and the current stress strain regime. This relationship is paramount for optimal location indentification of the fracturing wells and corresponding design together with an estimation of the subsequent recovery. Also, the rock mechanic simulation study would yield a comprehensive result with respect to the reservoir mechanical integrity while conducting the hydraulic fracturing operation to increase the well productivity.

This integrated workflow is considered as the key step for tight oil reservoir development, and it can be expanded to unconventional resources for a better reservoir characterisation and reservoir development. The study was performed within close collaboration within the teams with comprehensive know-how sharing and exchange.
Permeability Prediction Considering Surface Diffusion for Gas Shales by Lattice Boltzmann Simulations on Multi-Scale Reconstructed Digital Rocks
Authors: Ning Yang , He Shuai , Liu Honglin , Wang Hongyan , Qin Guan
Published: November 2016

The apparent permeability function in kerogen is developed by combining effects of viscous flow, Knudsen diffusion, and surface diffusion, in which the surface diffusion is defined as the transport of adsorbed gas due to the difference of adsorbed gas concentrations. The concentration of the adsorbed gas is quantified by the monolayer adsorption coverage and the specific surface area in shale. Weighting coefficients of viscous flow and Knudsen diffusion are determined based on the probabilities of collisions frequency between gas molecules and between gas molecules and pore walls. Analyzing the effect of surface diffusion, we found that the mass flux contribution of surface diffusion was dependent on many parameters that include pressure, temperature, pore size, specific surface area, etc. The apparent permeability function is further incorporated into the generalized lattice Boltzmann method (LBM) for porous media. A 3D nanometer-scale kerogen digital rock including macro-pores and larger-scale digital rocks including mineralogical components are reconstructed based on the focused ion beam-scanning electron microscopy (FIB-SEM) and Nano-CT experiments, respectively. The kerogen structures (1.53μm3) from FIB-SEM experiments distinguish macro-pores (>10nm) and kerogen solids. Kerogen solid is permeable as micro/meso-pores (1-10nm) exist in nature but are lost by the FIB-SEM experiment. The apparent permeability function is assigned locally on permeable kerogen solids. In Nano-CT digital rocks (413μm3), 4 different mineralogical components have been differentiated. Rock/fluid properties of shales in nanometer scale and micrometer scale are obtained by performing LBM simulations on digital rocks. The relations of methane permeability in kerogen with pressure, temperature, average pore diameter, and specific surface area have been investigated for the FIB-SEM digital rock. In addition, we have investigated the effects of organic contents on methane permeability in shale by comparing the simulation results of 3 different Nano-CT digital rocks.
ICD Design Optimisation with Single-Well Dynamic 3D Modelling and Real-Time Operation Support
Authors: van der Bol Linda , McCarty Andrew , Pritchett James , Sripornprasert Yurawoot , Goh G. , Ridho M. , Natapak R. , Sowmyanarayanan N. M.
Published: November 2016

Horizontal wells are well-recognized as one of the most effective innovations in exposing the wellbore to maximum reservoir contact and drainage area to improve recovery economics. It creates lower pressure drop to achieve better productivity compared to vertical/deviated wells. In order to enhance sweep efficiency, horizontal wells can be completed with Inflow Control Devices (ICD). ICD completion creates a more uniform inflow distribution along the production interval of the horizontal well. It aims to delay water breakthrough at high permeability zones and to provide better well clean up at initial production. In general, the performance evaluation shows that horizontal wells with ICD's have better sustained productivity than horizontal wells completed open hole or with screens.

ICD completion design was previously done based on near-wellbore data only. A new methodology has been applied by tailoring the ICD completion design with fine-grid dynamic 3D simulation that is fast enough to be used for real-time model optimisation while drilling. 3D simulation enables the optimisation for the number and placement of nozzles and packers by maximising the utilisation of reservoir information. The improvement on delivering ICD completion design also includes torque and drag analysis on every horizontal well candidate.

The new ICD completion design workflow has been applied since 2015. The real-time single-well dynamic 3D simulation-based design results in a better understanding of the completion options and their performance predictions. Various ICD completion scenarios, from constant nozzle sizes to varying nozzle sizes, and different packer numbers and placements are simulated. The new 3D simulation tool is able to provide time-lapse effects of cumulative fluid (oil and water) production for different flow rates. Additional pressure drop across the completion is modelled for different nozzle configurations. Based on these simulation results better informed decisions can be made regarding the nozzle sizes and numbers. In addition, the proposed ICD completion run-in-hole tally is evaluated in the torque and drag simulator to ensure the proposed ICD completions can be run to total depth (TD). The results of these two simulation steps are combined to optimize the final ICD completion design.
Advanced NMR and MRI Methodologies for Wettability Characterization in Carbonate Reservoirs
Authors: Matenoglou G. , Kelessidis V. C. , Garcia A. P. , Heidari Z. , Fardis M. , Anastasiou A. , Papavassiliou G.
Published: November 2016

The heterogeneity of carbonate reservoirs strongly influences their petrophysical properties and oil recovery procedures. Among many reservoir characterization techniques, NMR stands as a unique tool for oil reservoir exploration. The basic advantage of the NMR method is that oil, gas, and water possess different NMR properties. Therefore, they can be distinguished quantitatively. In this work we have combined NMR Laboratory methods and pore-scale numerical simulations, with MRI techniques in order to elucidate the oil/water-rock interactions of mixed-wet carbonates at molecular scale and on the basis of this information to acquire a quantitative measure of wettability. T2, D and D-T2 NMR measurements were performed on limestone core. Water and two types of oil, with different viscosities, were used in the experiments. Pore-scale numerical simulations of magnetization decay on samples taken from both rock types in the presence of different spatial distribution of fluid saturations and wettability assumptions were performed using a random walk algorithm. A sensitivity analysis were performed on the impact of wettability on T2 distribution in the two rock types. The T2 and D distributions were extracted from measured magnetization decay by implementing a new non-negative Tikhonov regularization algorithm, while for the D-T2 experiments a 2-D version of this algorithm was developed and implemented. For the MRI experiments CPMG trains were implemented for calculated T2 Images, and Diffusion Tensor Imaging methods, in order to acquire spatially resolved T2 and D values. The results of numerical simulations were compared against laboratory experiments.
Transport Properties of Natural Gas in Shale Organic and Inorganic Nanopores Using Non-Equilibrium Molecular Dynamics Simulation
Authors: He Shuai , Ning Yang , Chen Tianluo , Liu Honglin , Wang Hongyan , Qin Guan
Published: November 2016

One of the most important characteristics of shale gas formation is that the majority of the natural gas in both organic and inorganic nanopores exists as adsorbed gas and, due to the pressure draw down, the desorbed gas flows into the adjacent fracture network from the shale matrix. Therefore, numerical investigations on the transport behavior of natural gas in the nanopores become increasingly crucial for better understanding the shale gas production performance due to the limitations of current experimental measurements.

In this paper, we applied boundary-driven non-equilibrium molecular dynamics (BD-NEMD) simulation to estimate natural gas transport diffusivity coefficients in both organic and inorganic nanopores. Type II kerogen molecules and montmorillonite clay molecules are used to model the nano-channel with various sizes and methane is used to model natural gas. Driven by an external force, high- and low-density gas regions have been formed and constant flow rate has been established as the system reaches steady-state. Pressure-dependent transport diffusivity coefficients of methane can be then determined based on 1st-order Fick's law. Due to the work done by the external force, the temperature of fluid will inevitably increase and introduce certain artifacts to the diffusivity coefficients. Therefore, fluid temperature must be carefully controlled during the simulation to mimic real isothermal flow experiments. Both convection and diffusion contribute to the gas transport in nano-channel. Results indicate that the molecular mean free path is smaller than the free gas region due to the nano-scale confinement effect. Transport diffusivity coefficients depend on Knudsen number as well as pore geometry. In the continuum regime (Kn < 0.1), transport diffusivity coefficients are mainly dominated by convection and independent on pore size. In the transition regime (0.1 < Kn < 10), gas transport can be estimated by Knudsen diffusion that transport diffusivity coefficients are size-dependent. Meanwhile, in the organic nanopore, similar correlation is observed with smaller characteristic Knudsen number. Deviations may be caused by the surface roughness.
Novel Abrasive Perforating with Acid Soluble Material and Subsequent Coil Tubing Jetting Assisted Stimulation Provides Outstanding Results in Carbonate Gas Well
Authors: Buenrostro Adrian , Abulhamayel Nahr , Malik Usman , Suwaileh Mohammad Bu , Driweesh Saad , Chacon Alejandro , Jimenez Fadul Jose Camilo , Noguera Jose
Published: November 2016

Abrasive perforating with coiled tubing (CT) is a technique that has been in the market for several decades and that has been proven as a very valuable alternative to conventional perforating with e-line. The application is even more valuable whenever a high rate or fracture stimulation treatment is to follow due to the significant reduction in tortuosity and pumping friction losses across perforations. One of the main drawbacks of this type of perforations is that it is a much lengthier process compared to conventional perforating, and it requires a large amount of fluids as well as additional CT runs in the well to complete. These drawbacks discourage the wide use of the technique for more conventional applications.

This paper discusses a novel approach to abrasive perforating with the first ever use of an acid soluble abrasive material and ending with coil tubing jetting assisted nitrified stimulation. The main advantage of the use of this abrasive material is that there is no need for additional clean out runs and changeover of tools, thereby significantly reducing operational time and fluid volumes. Just as well, the benefits of combining the enhanced connectivity to the reservoir and the coil tubing jetting assisted stimulation were reflected in outstanding gas production results, which exceeded all expectations. Finally, as an added benefit, given the nature of the focused stimulation, this type of treatment in specific cases can replace plug-and-perf or multistage fracturing completions, thereby eliminating operational risks and added completion costs.
Subsea Insulation Resistance Monitoring
Authors: Wisselink Martijn , Somboonpakdeekun Kittipong , Kiertkul Suphawat
Published: November 2016

The subsea control system plays an essential role in subsea production. The integrity of the supporting subsea cables is therefore vital. To assess integrity of these cables the conventional method uses 500VDC test in accordance with ISO-13628-5/API 17E. This test is typically performed by connecting a downline from a support vessel to the subsea cable. The test set-up has issues associated with Humidity, Downline Cable Performance, Schedule, and subjective Interpretation. In addition, there is a risk of operator error and very low levels of insulation resistance are difficult to measure.

A new low voltage measurement technology, has been trialed during a 2015 campaign as an alternative to the conventional method. This new method was expected to address at least some of the identified issues.

The low voltage meter uses just 3.3VDC with the insulation resistance measuring range of 1kΩ to 10GΩ. The unit can be deployed by the ROV or diver without a downline cable. An offshore trial was performed on four standard subsea cables within an existing umbilical. The umbilical length of was 18 km and two conductors with sizes of 10mm2 and 6mm2 were tested.

The test results were compared with a measurement by a conventional 500VDC meter with a downline, and a similar test from the far end of the cable at the host facility with the same 500VDC meter. The results of the conventional 500VDC offshore test showed a wide range of sometimes illogical readings, whereas the Low Voltage test at 3.3VDC appears to show more consistent and rational results. As such, it is concluded that the Low Voltage test is actually more reliable than the conventional method.

The added benefit of the Low Voltage meter is that it can pick up low insulation values under 2MΩ comfortably, where the 500VDC meter struggled and failed to register a result.

These low Insulation Resistance values are still well above the operating threshold of the subsea control system, and as such, being able to quantify values between 500KΩ and 5 MΩ is an added benefit to confirm the integrity of the poor insulation subsea cables.

A test on a similar cable of 20km under factory conditions showed a good correlation between 500VDC conventional testing and the 3.3VDC testing with the Subsea Low Voltage meter.

Offshore testing can be significantly simplified with this metet, and overall schedule reduced. This in turn would save substantial costs during offshore inspection and fault finding campaigns. The result of the test by the new technique is more reliable, consistent and cost effective method to confirm Insulation Resistance in a Subsea Cable System.
Integrating Wireline Measurements to Provide Geomechanical Solutions: A Case Study for Optimizing Drilling by Improving Wellbore Stability in a Complex and Tectonically Active Region
Authors: Roy Sunit , Roy G. K. S , Chauhan R. S. , Bahuguna Somesh , Zacharia Joseph , Chatterjee Chandreyi , Basu Jayanta , Bhuyan Priyanuz , Talreja Rahul
Published: November 2016

In recent years, exploration in northeast India has focused mainly in the area south of the Naga fault. This area is tectonically active with complex folding and faulting. Target formations are in excess of 3,000m through these complex structures. ONGC has drilled several wells in the Tripura region of northeast India. Although results were encouraging, the main challenges faced during drilling were various well control and instability events: kicks, tight hole, stuck pipe, lost in hole, etc. The causes of this instability were difficult to isolate. Experience from past wells also indicated the existence of overpressure in the Middle Bhuban Formation, which could not be accurately predicted by surface seismic data. Hence, drilling through these highly stressed and overpressured formations led to excessive NPT and cost. In addition, severe hole enlargement and rugosity through eventual reservoir sections resulted in poor logging conditions and uncertain reservoir evaluation. As a result, access and interpretation of the reservoirs, to prove and produce reserves, is a major challenge in this region. In this paper, two case studies are presented to show how a geomechanics-based approach has significantly improved drilling rates by reducing the drilling-related problems. New wells were drilled within 40% of the planned number of days. Better hole conditions not only improved drilling performance but also led to huge improvements in reservoir evaluation and the identification of unloading mechanisms, probably caused by uplift due to thrusting, in the Middle Bhuban Formation. Integrated study provided valuable information about overpressure and stresses acting in this field/structure for future drilling.
The Performance of an ACROSS Permanent Seismic Source for Time Lapse Seismic at the Aquistore CO2 Storage Site
Authors: Nakatsukasa Masashi , Kurosawa Isao , Kato Ayato , Takanashi Mamoru , White Don J , Worth Kyle
Published: November 2016

Repeatability is one of the most important factors for time-lapse seismic surveys. Several types of permanent seismic sources have been developed previously to improve repeatability but monitoring of deep targets is still challenging because of the small power of such sources. We operated an ACROSS (Accurately Controlled, Routinely Operated Signal System) permanent seismic source at the Aquistore CO2 storage field in Saskatchewan, Canada. This source is known to excite continuous highly repeatable seismic signals by rotating an eccentric mass and to generate large force that is comparable to Vibroseis. This study analysed the quality and repeatability of ACROSS data (before massive CO2 injection) acquired in 4 periods (December 2014, and March, June, and October of 2015). Target reflections from 3300m depth can be observed on the ACROSS shot gather. After stacking over several hours, the S/N ratio of a raw shot gather from ACROSS is found to be comparable with a Vibroseis gather. Although low frequency and high amplitude noise is not negligible at near offset, the quality and repeatability of far offset data are excellent as the time shift calculated by cross correlation between different data is basically less than 1 milisecond. Data in March show a few milisecond time shift on all traces which is presumably caused by near surface changes locally around ACROSS but a global matching filter successfully corrected the time shifts and reduces its median to 0.74 ms which is less than expected time shifts by a previous study. This study indicates the high potential of an ACROSS survey to detect small changes for deep targets.
Minimising Image Distortion by Depth Modelling: A Case Study for Arthit Field, Gulf of Thailand
Authors: Satitpittakul A. , Boonysaknanon P. , Uttareun R. , Sootlek P. , Guo M.
Published: November 2016

Seismic imaging distortions in South Arthit area are mainly fault shadows and reflection horizon push downs (saggings) in PSTM volumes. Target reservoirs in the area are located near fault planes and therefore accurate fault imaging is essential for well planning and operation safety. Incorrect seismic images from PSTM method could lead to high uncertainty during interpretation and volume estimation. It's well known that PSTM technique has limited capability in handling image distortion beneath shallow anamalies and large-scale faults and therefore PSDM is required. Using more advanced depth imaging technique, including high resolution 3D reflection tomographic inversion, channel calibration, fault shadow correction, and by collaborating with South Arthit Asset Interpretors, DPC team successfully constructed a depth velocity model that minimizes saggings, and other imaging distortions in the legacy PSTM volume. Comparing with the PSTM volume, the new PSDM volume shows significant imaging improvement: eliminated sagging on deeper reflections below the shallow anomalies (channels and localized geological bodies), minimized fault shadow effects along major faults, and restored seismic amplitude in the fault zone. Fault planes can be interpreted with higher confidence, allowing better well path design with more accurate safety distances. In conclusion, advanced depth velocity modelling and PSDM imaging have proven to be a useful tool in minimizing seismic image distortions and reducing risks and uncertainties for South Arthit field development.
Investigation of Naphthenates Crude Oil Types and Behaviour to Induce Soaps-Microemulsion and Soap-Fines Foam in Malaysian EOR Fields
Authors: Borhan N. , Salleh I. , Ibrahim J. M. B. M. , Farrell A. R. , Nichols D. A. , Graham G. M.
Published: November 2016

The studies involves several unique case for EOR fields in which crude oil samples were collected from from peninsular Malaysia and Borneo. These fields has different reservoir characteristic in pressure, temperature and gas composition. Five Crude Oil from EOR field were undergone Naphthenate acid extraction using acid IER techniques for further instrument analysis to classification of Naphthenate acid type's component. Comparison of soaps-microemulsion generated was then analyse using static bottle test and Naphthenates/Emulsions Flow Rig Tests. The findings shows the Malaysian crude oil is able to be classified by type of naphthenate acid which are mono-protic acid generating sodium carboxylate soap and tetraprotic acid known as ARN which leads to calcium naphthenate deposit. There are fields that located nearby each other has different characterization of crude and types of acids which leads to different type and severities of soaps-microemulsion and soaps-fines foams formation from apllied EOR chemical. Statics bottle test at higher water cuts shows significant differences with observation from Naphthenates/Emulsions Flow Rig Tests. From this paper classification of Naphthenate acid for Malaysian crude oil has been established with its behavior to induce Soaps-Microemulsion and Soap-Fines Foam in Malaysian EOR Fields using more representive method by Naphthenates/Emulsions Flow Rig Tests.