bluuebunny/crossref_metadata_2025_split huggingface dataset:
Residual Trapping of CO2 in Water-Wet and Mixed-Wet Carbonates for Carbon Utilization in Mature Carbonates Oil Fields
Authors: Al-Menhali A. , Krevor S. 
Published: December 2015

AbstractIn an energy hungry world, fossil fuels are predicted to remain the dominant source of energy for a long time. Burning more fossil fuels will increase CO2 emissions in the atmosphere and will consequently increase the challenges of climate change mitigations. Carbon capture and storage (CCS) in deep saline aquifers is an important process for CO2 reduction on industrial scales but it is not economically attractive. Residual trapping of CO2 through capillary forces within the pore space of the reservoir is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO2 migration within the reservoir. Carbon capture, utilization and storage (CCUS) in mature oil reservoirs can have a significant energy, economic and environmental benefits and is considered an important component in achieving the widespread commercial deployment of CCS technology. Residual trapping in mixed-wet systems, however, is assumed to be less efficient than in water-wet systems. In this study, we compare residual trapping efficiency in water-wet and mixed-wet carbonates systems on the same rock sample before and after wettability alteration by aging with crude oil. The observations were made at reservoir condition in a core-flooding system that included high precision pumps, temperature control, the ability to recirculate fluids for weeks at a time and an x-ray CT scanner for in situ saturation monitoring. The wetted parts of the flow-loop are made of anti-corrosive material that can handle co-circulation of CO2 and brine at reservoir conditions. We report the initial-residual CO2 saturation curve and the resulting parameterisation of hysteresis models for both water-wet and mixed-wet systems. A novel core-flooding approach was used, making use of the capillary end effect to create a large range in initial CO2 saturation in a single core-flood. Upon subsequent flooding with CO2-equilibriated brine, the observation of residual saturation corresponded to the wide range of initial saturations before flooding resulting in a rapid construction of the initial residual curve. Also, multiphase flow observations were made on a single carbonates core sample. It was made first on its original water-wet state, then were measured again after altering the wetting properties to a mixed-wet system. In particular, CO2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly.
Multifunctional Nanoadditive in Water Based Drilling Fluid for Improving Shale Stability
Authors: Taraghikhah S. , Kalhor Mohammadi M. , Tahmasbi Nowtaraki K. 
Published: December 2015

Abstract
Wellbore stability and formation damage are of great interest and significance in drilling industry. It is estimated, each year, millions of dollars are lost due to wellbore instability problems which are resulting from exposure of shale to drilling muds. The main objective of this research activity is to improve shale inhibition and wellbore stability by using Silica nanoparticles in mud formulation. Furthermore, it is also intended to use this nanoadditive as a multifunctional mud additive to decrease fluid loss, improve lubricity, avoid shale swelling and modify rheological properties. In order to achieve these objectives, experimental procedures have been planned in the following sequences; A) Different concentrations of Silica nanoparticles are used in conducting experiments in order to determine the nanoparticles concentration range that yields the optimum shale inhibition. B) Further experiments are conducted on the evaluation of rheological properties and fluid loss via API standard methods. C) Lubricity and shale swelling tests are performed via relevant standards. D) Overall evaluation of laboratory-prepared water based drilling fluid is performed and the results are presented and compared with the blank samples. In conclusion, according to the acquired results including nanoadditives in drilling fluid and comparing them with blank samples, it was found that the most economical and effective concentration of nanoparticles is below 1% w/v, which lead to an acceptable shale inhibition effects by plugging the nanosized pores. These effects are analyzed and reported graphically. Various charts and figures show the enhancement in rheological properties such as yield point by adding small amount of nanoadditive in comparison with ordinary vicosifiers in drilling fluids. The most significant achievement in this research is the cost effectiveness of the nanoadditive. Not only can we improve mud performance with a lower cost in comparison with previously used drilling additives, but also by further modifications, these additives can replace the ordinary drilling additives. Needless to say that such change has a considerable reduction in drilling fluids costs. Several works have accomplished in relation with applying Silica nanoparticles in drilling fluid formulation and approximately in all of these works, only higher concentrations of nanoparticles (more than 10%wt) can be applicable in the shadow of surfactants and ultrasonication methods for sufficient dispersion. The striking feature of this research is the consuming of nanoparticles in lower concentrations (maximum 1% w/v) and without the assistance of surfactants.
Reservoir Modeling of Complex Thin-Bedded Deep Water Deposits Integrating Well Data, Seismic Inversion and Depositional Model from Offshore Sabah, Malaysia
Authors: Souche Laurent , Mahdavi Ramin , Mahmod Nor Mahira , Alim Syarafina , Masoudi Rahim , Basu Debnath 
Published: December 2015

Abstract
The studied field, located offshore Sabah, Malaysia is composed of a succession of thick-bedded sand lobes, thin-bedded heterolithics and shale dominated mass transport deposits (MTDs). While the thinly bedded units contain significant hydrocarbon reserves, the distribution and continuity of sand bodies within these units cannot generally be derived from well data alone. Modern analogues suggest that these thin beds are likely composed of small scale sandy lobes embedded into a shale background. In order to better understand the vertical and lateral connectivity of these turbiditic elements, a numerical model integrating well data and seismic inversion results was built, constrained by a conceptual depositional model based on analogue data.
Multi-point geostatistics (MPS) were used as a platform to combine geological knowledge - in the form of a realistic training image, well measurements and geophysical trends. In order to reproduce observed facies proportions and architecture, the training images were generated using a novel user-guided, semi-automated workflow based on object-distance simulation. Reproducing the vertical heterogeneity of the model observed in thinly bedded units while retaining the lateral variability evidenced by seismic inversion was achieved by creating first set of facies probability cubes from the seismic inversion results using supervised neural-network estimation, then refining these probabilities by calibrating them to vertical proportion curves extracted from high-resolution facies logs. This technique enabled reproducing complex depositional patterns such as compensational stacking and hierarchical distribution of facies. It also allowed sedimentary bodies directly visible on the seismic inversion results to be integrated explicitly into the facies model. The simulated facies distribution was then used to constrain petrophysical property population, yielding detailed and realistic dynamic models.
While the presented approach is specifically tailored to the modeling of thinly bedded deep water environments, the innovative techniques proposed for generating a "photorealistic" training image and for integrating seismic-scale results with high resolution well data could also be used for representing a varied set of depositional settings.
Microporosity Spatial Modeling In A Giant Carbonate Reservoir
Authors: Stanley Rowan , Guidry Sean , Al-Ansi Hussain 
Published: December 2015

AbstractA challenge for carbonate rock classification in reservoir models is the seemingly chaotic variability in the total pore system which ultimately controls petrophysical and dynamic behaviour. The aim of this study is to describe and spatially model a unified rock-typing scheme aligning the dual requirement for: 1) hydraulically consistent rock classes suited to numerical flow simulation, and 2) heterogeneity shaped according to field-scale geological anisotropy. Description of a suite of samples derived from the Jurassic Arab Formation reservoirs in the Dukhan Field, Qatar, facilitated the following:Definition of petrophysical rock classes based on consistent pore and capillary pressure characteristics. Evaluation of the rock-type 3D spatial distributions to ensure conformance with inferred geological patterns. Computation of absolute permeability ranges based on measured responses to the fractional proportions of pore systems. Creation of an initial saturation model accounting for the compound saturation fractions related to the pore system components. Implementation of the concepts in a novel geomodeling workflow.Statistical analyses of almost a thousand pore throat radius distributions and capillary pressure responses reveal a remarkably consistent set of micro-textural associations. Hierarchical clustering analyses define an ordered system of building blocks comprising five dominant pore systems. The macro-porous samples (&gt;2µm pore throat radius – PTR) are distinctly bimodal in two classes (Macro1 and Macro2), while the micro-porous samples have typically unimodal PTR and form three clusters: Micro1 (2 – 0.2µm), Micro2 (0.2 – 0.02µm) and Micro3 (&lt;0.02µm).Each rock element is a variable mixture of the five textural building blocks and the relative proportions are utilized to define the rock classification. Spatial continuity and anisotropy are shaped by geological trend vectors interpreted from collocated lithological and depositional texture distributions. This approach meets a dual objective of accounting for the myriad of geological processes implicit in the rock fabric while also providing a rock classification applicable for reservoir engineering and flow simulation purposes.
The Effect of Reservoir Conditions on Wetting and Multiphase Flow Properties in CO2-Brine-Rock System
Authors: Al-Menhali A. , Niu B. , Krevor S. 
Published: December 2015

AbstractThe wettability of CO2-brine-rock systems will have a major impact on the management of carbon sequestration in subsurface geological formations. Recent contact angle measurement studies have reported sensitivity in wetting behaviour of this system to pressure, temperature and brine salinity. We report results of an investigation into the impact of reservoir conditions on capillarity and multiphase flow through effects of wetting. The semi-dynamic capillary pressure core flooding technique was used with in situ saturation monitoring. The observations were made using a reservoir condition core-flooding laboratory that included high precision pumps, temperature control, the ability to recirculate fluids for weeks at a time and an x-ray CT scanner. The wetted parts of the flow-loop are made of anti-corrosive material that can handle co-circulation of CO2 and brine at reservoir conditions. Eight reservoir condition capillary pressure characteristic curves were measured using CO2 and brine in single fired Berea sandstone at pressures (5 to 20 MPa), temperatures (25 to 50°C) and ionic strengths (0 to 5 M kg-1 NaCl) representative of subsurface reservoirs. A ninth measurement using an N2-water system provided a benchmark for capillarity with a strongly water wet system. In all cases, the capillarity of the system, scaled by the interfacial tension, were equivalent to the N2-water system within measurement uncertainty. Thus reservoir conditions did not have a significant impact on the capillary strength of the CO2-brine system through a variation in wetting. In this work we report the results of the first study looking systematically at the impacts of reservoir conditions on the effective wettability in the CO2-brine-sandstone system. A new method is presented to quantify shifts in effective wetting properties with changing reservoir conditions. We find no impact within the range of reservoir and flow conditions relevant to CO2 storage, consistent with traditional multiphase flow theory but despite observations by others suggesting that wetting properties and multiphase flow in this system are sensitive to pressure, temperature and brine salinity. This provides definitive confirmation that the CO2- brine system performs as a strongly water-wet system in sandstone rocks and the use of analogue fluids for this characterisation may be useful when the full reservoir conditions cannot be replicated in the laboratory. The spatial saturations were also investigated using x-ray computed tomography and were found to be invariant with different reservoir conditions in homogeneous samples. The findings confirm the role of residual trapping in capacity estimates and provide a comprehensive dataset for flow modelling in water wet reservoirs.
Mitigating Drilling Dysfunction Using a Drilling Advisory System: Results from Recent Field Applications
Authors: Payette Gregory S. , Pais Darren , Spivey Benjamin , Wang Lei , Bailey Jeffrey R. , Pastusek Paul , Owens Michael 
Published: December 2015

Abstract
The ExxonMobil Drilling Advisory System (DAS™) is a rig-based drilling surveillance and optimization platform that encourages regular (guided) drill-off tests, carefully monitors drilling performance and provides recommendations for controllable drilling parameters to help improve the overall drilling process. It is well known that drilling with dysfunction(s), such as BHA whirl or bit stick-slip, among others, can damage drilling tools, lead to poor borehole quality and result in significant reductions in Rate of Penetration (ROP). The ultimate objective of DAS is to help drillers achieve consistently better and longer bit runs by identifying and mitigating drilling dysfunctions.
In this paper we describe the DAS workflow, provide an overview of many of the key technical components of DAS and summarize results from several recent field applications. The DAS workflow includes a learning (or calibration) mode that encourages the driller to explore different operating parameters by conducting drill-off tests, which in turn allows the system to build an understanding of performance trends. This understanding is then exploited by an application mode which leverages results obtained during the learning (or calibration) phase. The workflow is iteratively applied in real-time as drilling operations and geological conditions change.
Key technical components of the DAS application include: high quality adaptive filtering algorithms for computing various drilling system performance measures (e.g., MSE, ROP, and stick-slip severity, among others), data encapsulation/dimensionality reduction techniques (i.e., the notion of "response points") and reduced order modeling techniques (simplices, smooth response surfaces, etc.) which are ultimately used to generate recommendations for improved performance.
Using examples from recent offshore field applications, we illustrate the use of adaptive filtering and data encapsulation to process noisy real-time data and extract meaningful trends to enable drilling performance optimization. We show how fitting response surfaces to response points can help elucidate, in real-time, the occurrence of classical drilling dysfunctions such as lateral vibrations (as manifest in increased MSE) and stick-slip torsional vibrations. Using results from recent applications of DAS to unconventional pad-drilling operations, we show the impacts of focused drilling performance limiter redesign and real-time DAS parameter changes on improved overall ROP in subsequent wells on a pad.
Fit-for-Purpose Treatment of Produced Water for Hydraulic Fracturing – A Permian Basin Experience
Authors: Sharma Ramesh , McLin Kristie , Bjornen Kevin , Shields Austin , Hirani Zakir , Adham Samer 
Published: December 2015

Abstract
ConocoPhillips is committed to creating a responsible water management plan in developing assets in the Permian Basin of West Texas. Sourcing water for the large multi-frac stimulations in West Texas is a well-known constraint on oil and gas development activities in the area. Additionally, large volumes of produced water (PW) have traditionally required clean up and disposal in injection wells. Rather than viewing these constraints only as challenges, ConocoPhillips realizes the tremendous opportunity to address both issues by treating and reusing PW for hydraulic fracturing operations. With this perspective, water management strategy development has become a truly collaborative, cost-effective, and integrated process that addresses the full life-cycle of water.
ConocoPhillips executed a multi-well reuse pilot program in the Permian Basin. A "fit-for-purpose" treatment scheme was deployed to selectively remove free oil, suspended solids, hydrogen sulfide, and iron as well as to inactivate microorganisms. While gravity separation was adequate for de-oiling and filtration for suspended solids, oxidation followed by coagulation and clarification was necessary for dissolved iron removal. The treated water iron concentration was below 5 mg/L whereas the turbidity was consistently below 10 NTU, making it suitable for well completions. When treating for H2S removal, the oxidation followed by filtration method was sufficient to reduce the H2S concentration to &lt;0.2 mg/L and achieve turbidity below 10 NTU. The treated PW was compatible with the new salt-tolerant friction reducer, achieving similar friction reduction compared to a standard friction reducer and fresh water. The treated PW used in hydraulic fracturing was also compatible with formation water as it was produced from the same formation. The sulfate reducing bacteria were non-detectable in the treated water after four weeks of storage.
The six month pilot operation, demonstrated that PW reuse is technically feasible and can be a cost-effective solution compared to other available water sourcing alternatives. The technical approach developed allowed use of salty produced water (&gt;220,000 mg/L TDS) for completion activities utilizing a new type of friction reducer. Based on the success of the pilot program, a full-field produced water reuse program has been initiated early in the appraisal and development phase of the project to reduce implementation risks and improve economics in a safe and environmentally responsible manner.
Strong collaboration led to success in these projects, and they were designed and executed through a significant team effort made by completion engineers, water treatment engineers, the asset development team, and the operations team. This paper provides an overview of the plan implemented for safe pilot operation, procedures for treatment of produced water and water quality results.
Discrete Fracture Network Modelling of Faulted and Fractured Apulian Platform Carbonates (Altamura Formation, Southern Italy)
Authors: Giorgioni M. , Panza E. , Agosta F. , Zambrano M. , Tondi E. 
Published: December 2015

Abstract
In order to better understand the relative contribution of background and localized deformation on the petrophysical properties of fractured tight carbonates, Discrete Fracture Network (DFN) models of representative outcrops were build up by using a stochastic approach. The study carbonates, which crop out along the vertical walls and pavements of an abandoned quarry of southern Italy, represent a surface analogue of the hydrocarbon reservoirs currently developed in nearby areas of Italy. The outcrops expose a well-layered, tight, Cretaceous limestone crosscut by both background (diffuse) and fault-related (localized) deformation.
Fractures show a high variability of their spatial and dimensional properties (length, intensity, aspect ratio and aperture), according to the different structural domains (fractured host rock, fault damage zone and fault core) in which they were surveyed. Such variability highlights the different scales at which the structural domains affect the tight carbonates, and can be considered a key challenge to construct a realistic reservoir model. DFN modelling of representative rock volumes of the fractured host rock showed that both volumetric (P32 and porosity) and hydraulic properties (correspondent permeability) are mainly affected by the two main sets of Non-StrataBound fractures (NSB). Equivalent porous media modelling, which include both fractured host rock and fault zones, showed that the overall permeability of the Fault Damage Zones (FDZ) is 2-to-4 orders of magnitude higher than the fractured host rock permeability. The FDZ can be therefore interpreted as fluid conduits that enhance fluid flow, which is controlled by both the dimensional properties of the fractures and by their aperture values.
Vertical Heterogeneity of Kerogen and Fluid Compositions in the Vaca Muerta Unconventional Shale Play and Assessment of Producible Fluid Composition and Quality
Authors: Elias R. , Gelin F. 
Published: December 2015

Abstract
To better understand potential vertical variability of the original kerogen quality in an unconventional reservoir we have carried out organic geochemical analyses on hundreds of rock and fluid samples coming from the Upper Jurassic / Lower Cretaceous Vaca Muerta Formation (Neuquén Basin, Argentina). The studied samples are derived from six wells located in different parts of the Neuquén "embayment" where the Vaca Muerta Formation reached distinct maximum thermal maturities. This natural maturity sequence ranges from the peak oil to dry gas window (VReq ~ 0.7 % to 1.8 %). Applied geochemical analyses comprise high-frequency TOC measurements on a centimeter scale, conventional Rock-Eval analyses on a decimeter scale, and meter by meter molecular and isotopic mud gas analyses. In addition we have performed molecular and isotopic analyses on several hydrocarbon liquid extracts and produced oils. Our data clearly indicate highly heterogeneous vertical distributions of organic matter contents on centimeter scales reflecting the fine shale laminations in the Vaca Muerta Formation. Despite the regional control of thermal maturity on liquid and gaseous hydrocarbon compositions we also observe at well scale some remarkable vertical compositional kerogen and fluid variability. Molecular and isotopic analyses on liquid hydrocarbon extracts document vertical differences in the source organofacies. These vertical organofacies variances are responsible for the distinct compositions/properties of the produced fluids at well scale.