bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Concept of Progressive Property Modeling, a Sequential Technique to Enhance the Utilization of Seismic Inversion Products and Lwd Property Measurements from Horizontal Wells into Static Models
Authors: Contreras David , Khalid Bahussain Esra , Susanto Maria Indriaty , Verma Ravi 
Published: November 2020

AbstractTo establish relationships between seismic derived acoustic impedance and LWD porosity measurements from several horizontal wells to be implemented into property modeling. This workflow is a sequential process that integrates property relationships from seismic scale to log scale using log data from a dozen of vertical wells and validate results at field scale with log data from about 50 horizontal wells.Overall process functions at grid-block scale in a 100x100mx1ft cell size following the four main phases. The first phase, involves exploratory data analysis and quality check. This is followed by a second phase of model building to concatenate all the required modeling steps. Third phase of model optimization explores the effect of all the parameters and data links defined in the process. Finally fourth phase involves validation to assess residual errors from the resulting porosity distributions and quantifying predictability of the model itself.A comprehensive and robust set of properties is generated by performing a recursive and convergent process of property modeling using lateral coverage from seismic inversion products and vertical resolution near well log scale. Independent analysis of different scales of porosity measurements are reconciled in this systematic approach by defining average distributions and descriptive statistics of reservoir properties at field scale. Variable data types, sample sizes and data resolution evolves across four different phases that integrates a holistic understanding of datasets in different dimensions.Quantitative analysis of seismic data ultimate correlates to a dense dataset from long horizontal wells. Final predictability of the model reaches a high confidence level (about 80% accuracy) when testing the predicted properties vs real measurements in about 50 horizontal wells. Multiple realizations of properties distribution matching all the available data is final output that provides a better understanding of reservoir property. This workflow allows total utilization of log data from horizontal wells into property distribution with no impact on overall statistics. No complex de-clustering operations are required as all the descriptive statistics are defined from vertical wells calibrated to core and seismic data. This methodology maximizes the value of LWD formation evaluation logs in property distribution, by combining the resolution of the logs along long horizontal wells with the strong lateral coverage of seismic inversion cubes.
The Houta Prospect Hammamet Basin, Offshore Tunisia as an Example of a New Play in an Old Basin
Authors: van Dijk Janpieter , Boulares Achref , De Vincenzi Luca , Gharieni Nawfel , Santoni Stefano 
Published: November 2020

Abstract
A new play concept is presented for the prospectivity of the Miocene of the Gulf of Hammamet (Central Mediterranean Pelagian Basin, offshore Tunisia), built upon three new elements: the role of the Langhian unconformity, the specific type of migration model, and the mechanism of tectonic inversion, based on an extensive subsurface mapping of the area, on vintage 2d and 3d and newly acquired and processed 3d seismic data using available well logs.
The sandstone reservoirs are part of the Oum Douil Group (Serravallian-Tortonian; e.g. Saouaf, Birsa, Zelfa, Somoaa, Beglia Fm’s), and are deposited in the Miocene foreland Basin which developed on the African continental margin, on top of the Langhian unconformity which shows substantial erosion of the Cretaceous-Paleocene sequences, and angular relationships as evident in seismic. We interpret this as related to a foreland bulge connected to the Early Miocene approaching of the Maghrebian (Atlas) mountain front from the North which culminated in the Late Burdigalian shortening pulse and Langhian transgression, a front that moved to the South during the Mio-Pliocene up to the Present position (Sicily-Tunisian Atlas).
Our analyses showed that important thickness variations occur in the Miocene deposits; Most of the discovered fields are related to older structural highs showing relatively thin reservoirs. Major burial occurred during the Pliocene deposition in the Jirba trough. All traps (fault bounded structures with sealing faults that in many cases reach the seafloor) are related to the Late Plio–Pleistocene tectonic pulse which inverted the thicker portion of the Miocene sediments which have become structurally higher and constitute the new prospects we identified (e.g. the Houta Prospect).
Source rocks are the Fahdene shales (Albian), deposited upon the Mesozoic rifted continental margin, and subcropping below the Langhian unconformity. Important reservoirs and regional seals exist between Fadhene Fm and Birsa Fm, making direct vertical hydrocarbon charge unlikely. Moreover, several fields show an effective regional vertical seal (Paleocene El Haria shale) between Birsa Fm and in the underlying producing Abiod limestones Fm (Upper Cretaceous). We postulate that hydrocarbons migrated through sub-cropping windows in the Langhian unconformity within the Ain Grab bioclastic limestones (deposited on top of it) as carrier beds, and that further migration occurred through juxtapositions on existing fault surfaces. This concept, new for the Miocene play in the Pelagian Basin, explains in a satisfactory way the hydrocarbon occurrences in the discovered fields.
The new play concept, which has been overlooked previously because the main exploration objectives were the deeper Mesozoic and Paleogene sequences in the structural highs, is a typical example of a New Play in an Old basin, which opens-up new hydrocarbon exploration opportunities in the Tunisian offshore area.
A Unique Approach of Numerical Simulation with Multistage Hydraulic Fractures Modeling of a Complex Regional Scale Unconventional Biogenic Gas Reservoir. A Case Study of Miocene Gachsaran Formation, Abu Dhabi, United Arab Emirates
Authors: Gueddoud Abdelghani , Al Hanaee Ahmed , Khan Riaz , Abdelaal Atef , Kurniawan Redy , Al Ameri Abdulla 
Published: November 2020

Abstract
Recently unconventional gas resources including the shallow biogenic gas reservoirs have received great attention around the world due to technical advances in the field development and corresponding large in-place resources. However, the technologies needed for the effective development of unconventional reservoirs are still behind the industry needs, for example the gas recovery rates from these unconventional resources are still very low.
The Miocene Gachsaran Formation across Onshore Abu Dhabi and Dubai possesses high potential of generating shallow biogenic gas. To understand and evaluate its capability for a promising gas resources a dynamic model and field development plan were generated based on a detail G&G analysis. The Gachsaran biogenic gas potential falls under the category of unconventional resources due to the existence of adsorbed gas within the organic matter and clay.
The paper provides a detailed numerical simulation approach from a modified commercial simulators to simplify analytical solutions for adsorbed gas in-place calculation and full field development plan. The construction of dynamic model to tackle the growing advances in drilling and stimulation technologies for such complex tight reservoirs have become possible. These reservoirs are still challenging to produce due to their complex geology, tightness and requirements of advance production technologies such as hydraulic fracturing to achieve economical production rates.
The gas flow mechanisms in nano-pores cannot be simply described by Darcy flow equation. In addition, due to large-scale fracturing, the conventional single porosity model is not enough to simulate the characteristics of these source rock type reservoirs. Furthermore, advanced simulation methods such as molecular dynamic simulation are computationally challenging and very time consuming.
To mitigate these challenges, two alternative unique approaches were considered to model these reservoirs: (1) application of analytical methods to characterize the primary characteristics of nano-pores, and (2) extending the conventional simulator to effectively model flow from the nano-pores gas reservoirs. The study describes the theory and application utilized to modify and enhance the capability of conventional simulator. Consequently, to properly estimate the adsorbed gas in-place and integrate the effects of Langmuir gas desorption and gas diffusion effects. Therefore, the dual-porosity model was built and coupled with local grid refinement to capture the associated hydraulic fracture design and properties. This robust modeling approach has provided an enhancement in the field development planning of such a complex regional scale unconventional reservoir.
A New, Data-Driven Methodology for the Integration of Seismic and Well Data Into Geological Model - Case Study Block 4, Offshore Angola, Lower Congo Basin
Authors: de Sá Mario , Ferreira Lidia. J , José Manuel. N , Simào Joào , Sonibare Wasiu Adedayo , Oyeleke Kehinde Zaid , Bouchet Francois D. , Darous Christophe , Fadipe Oluwaseun , Kolivand Hassan , Hasan Hesham , Chidundo Maximiano , Khan Waqar Ali 
Published: November 2020

Abstract
The acquisition of high-resolution and high-fidelity seismic data opens the possibility of precision reservoir characterization, particularly for those formations that do display a very pronounced Amplitude Versus Offset (AVO) response. In a traditional approach, the integration of seismic and well data information is driven by the ideas and view of the geologist, whose ideas and views might introduce bias in reservoir representation. It is undeniable that the guidance of the model construction by the geologist is an absolute requirement where seismic data limitations (quality, fidelity or accuracy) does not allow extracting a high-resolution reservoir description as an input to the static model construction.
This is evolving: Where AVO effects at reservoir level are significant, the grade of both seismic data and petrophysical measurements now available allow a very precise description of the reservoir, in terms of reservoir geometry and reservoir property distribution. In the study area, AVO response in the Upper Miocene turbiditic deposits, offshore Angola are suitable for detail reservoir characterization.
In this paper, we shall demonstrate through a real case how the results of seismic inversion and attribute analysis have been used for the characterization of depositional elements and the modeling of reservoirs. We shall present first how seismic inversion results have been integrated with facies defined from logs, and how this was used to confirm and identify fluid type and contacts verified at wells, as well as for the delineation of structural and stratigraphic reservoir boundaries. A systematic approach to constructing the 3D static model was applied. The top reservoir was picked in detail, allowing for the channel geometries to be sculpted out using seismic inversion results. The integration of qualitatively and quantitatively delineated sand-body architecture, geometry and orientation from seismic data. Sequential Indicator Simulation method, using well data, allows the facies to be modeled hierarchically through a combination of deterministic and stochastic approaches.
The advantages of this methodology are: (i) integrating fully facies characterization and geological concepts with seismic response, (ii) reducing uncertainty on reservoir distribution and extent and, (iii) constructing of a coherent reservoir description fit for dynamic model even with limited number of wells.
Redevelopment of a Supergiant Southern Iraqi Oil Field with Horizontal Wells
Authors: Khan Sameer A. , Hassan Fadhel A. , Wang Junwen , Gan Junqi , Liu Yang , Patz Joseph F. , Abdulshbeb Saeb K. , Al Lawe Erfan M. 
Published: November 2020

AbstractThis work encompasses redevelopment of a supergiant southern Iraqi oil field from fully vertical to primarily horizontal wells. The subject reservoir is a massive world-class carbonate limestone reservoir containing 23 °API oil and is the dominant reservoir in a set of vertically stacked reservoirs. This reservoir is a part of a large anticline which is oriented north-northwest. The formation is Middle Cretaceous and has a subsea depth of 2100–2600 m. The reservoir was initially developed on a 200 acre inverted 9-spot pattern, and was on primary oil production until reservoir pressure dropped and production declined. Later, water injection started at centers of the 9-spot pattern. Development drilling was projected with future addition of vertical infills at 100 and then 50 acre patterns.During pressure drop due to primary production, water encroachment from flanks occurred, particularly, in the thin super-high permeability (vuggy) layers present in the reservoir; however, this was not clearly evident at early stages. By the time of starting pattern water injection with comingled injection and production in vertical wells, there was clear evidence of rapid water movement in the vuggy layers. As water injection progressed, the severity of watercut evolution in vertical wells rapidly progressed, necessitating change of the depletion plan. Continued development of the field with vertical infills would result in unsustainable water production and injection requirements, and lower oil recovery.A redevelopment effort was initiated to overcome these challenges. Geologic and simulation models were modified to reflect the evolved understanding of geology. Appropriate distribution of high permeability layers was introduced and calibrated to production data, in particular, water breakthrough timing and watercut evolution. The main change in the redevelopment plan has been to shift emphasis from drilling vertical infill wells to a fewer horizontal wells targeting low permeability zones which comprise most of the reserves. Reservoir development of the massive lower section is planned with 2 km long horizontal wells with injectors located in lower part of the reservoir and producers higher arranged in a line drive. Upper reservoir development is planned by working over existing comingled vertical wells to upper reservoir only thus decoupling upper and lower comingled production.The redevelopment plan achieves the business target rate with a much longer plateau duration at lower cost. The plan effectively utilizes existing vertical wells in addition to drilling new horizontal wells for recovering oil from lower, tighter reservoir. Initial performance of horizontal wells have shown very promising results with boosted dry oil production. This updated development plan is now in full execution phase and can provide redevelopment ideas for other brown fields with similar issues.
Light Weight Structure LWS Installation Using Jack up Rig
Authors: Nor Azhar Norshaiful Azril 
Published: November 2020

Abstract
This paper is to highlight the success offshore installation campaign of D28JT-A and D18JT-D platforms utilizing Jack-Up Rig (JUR) and the technical challenges during offshore execution. The installation work limitations and difference in installation sequence are also presented in this document. Light Weight Structure (LWS) has become one of the novel alternatives and cost-effective solutions for marginal field offshore facility in the recent years in meeting tight budget for Final Investment Decision (FID).
The basic concept of LWS is to design the topside and substructure that could be lifted by JUR for installation. Hence, a minimal facility design approach was selected for this project due to limited capability of the selected JUR. While the basic principle of load out and transportation remains the same, methodology and systems used to execute the offshore installation campaign are vary significantly. This concept has posed numerous technical and operational challenges.
PETRONAS Carigali Sdn. Bhd. (PCSB) has undertaken the development of D28JT-A and alliance with partner for D18JT-D development. Both projects are located at offshore Sarawak in Malaysia. D28JT-A and D18JT-D are wellhead platforms utilizing design one and built many concepts where both platforms were similar in design with only difference in weight. Both platforms were installed by the same JUR.
The installation work required high precision engineering and execution especially during topside lifting considering the close proximity (≪ 1 meters) between substructure and topside. Position Monitoring System and Weather Monitoring System were essential and closely monitored for safe work execution. Transportation marine vessel dynamic positioning (DP) system checks were conducted prior approaching the substructure. Both Topsides were lifted and set down within 3.25 hours. These projects had successful HSSE track record with zero LTI or incident.
It is proven that the installation of light weight structure by JUR is technically feasible and become a benchmark for future projects especially for marginal field development. Utilization of JUR for offshore platform installation significantly reduce the offshore installation cost due to JUR daily charted rate (DCR) and sharing mobilization and demobilization of installation and drilling campaigns.
This paper should be an interest for marginal field development utilizing "fit-for-purpose" design facilities.
Physics Driven AI Coreflooding Simulator for SCAL Data Analysis
Authors: Mathew Eric Sonny , Tembely Moussa , AlAmeri Waleed , W. Al-Shalabi Emad , Shaik Abdul Ravoof 
Published: November 2020

Abstract
Two of the most critical properties for multiphase flow in a reservoir are relative permeability (Kr) and capillary pressure (Pc). To determine these parameters, a meticulous interpretation of coreflooding and centrifuge experiments is necessary. In this work, a machine learning technique was incorporated to assist in the determination of these parameters quickly and synchronously.
A state of the art framework was developed where a large database of Kr and Pc curves were generated based on existing mathematical models. This database was used to perform thousands of coreflood simulation runs representing drainage steady state experiments. The results obtained from the corefloods including pressure drop and water saturation profile along with other conventional core analysis data were fed as features into the machine learning model. The entire data set was split into 70% for training, 15% for testing, and the remaining 15% for the model validation. The 70% of the training data teaches the model to capture fluid flow behavior inside the core. K-fold cross validation technique was also utilized to increase the accuracy of the model. The trained/tested model was thereby employed to estimate Kr and Pc curves based on available experimental results.
The values of the coefficient of determination (R2) was used to assess the accuracy and efficiency of the developed model. The respective cross plots indicate that the model is capable of making accurate predictions with error percentage less than 2% on history matching experimental data. Furthermore, the latter implies that the AI-based model is capable of determining Kr and Pc curves with less effort and better reliability as opposed to the conventional way of creating an entire simulation model. Additionally, the results include multiple options for Kr and Pc curves from which the best solution can be determined using engineering judgement. This is unlike solutions from existing commercial software, which usually provides only a single solution. The model currently focusses on the prediction of Kr and Pc curves for drainage steady state experiments; however, the work can be extended to capture the imbibition cycle as well.
CFD Simulations of Oil Viscosity and Emulsion Effects on ESP Stage Performance
Authors: Banjar Hattan , Zhu Jianjun , Zhang Hong-Quan 
Published: November 2020

Abstract
Oil-water emulsion effects on a seven-stage electrical submersible pump (ESP) performance are studied experimentally and numerically with computational fluid dynamics (CFD) simulation. At different oil-water fractions, temperatures, and ESP rotational speeds, the performance of the third stage was measured. The intention of this work is to validate and compare experimental data with CFD simulation results. In addition, flow structures can be visualized through the CFD simulation for oil-water emulsion flows.
Density and mass flow rate are measured using the mass flowmeter while the emulsion effective viscosity is derived from the pipe viscometer installed downstream of the ESP. CFD simulations are carried out with estimated droplet sizes of the dispersed phase for oil-water flows, and the results are compared with the experiments. For the wall roughness, a higher value is used due to the extended use of the ESP. The three-dimensional, steady-state Reynolds-Averaged Navier–Stokes (RANS) equations with standard shear stress transport (SST) turbulence model are solved in ANSYS CFX solver by employing the frozen-rotor technique. With high-quality structured hexahedral mesh grids, the simulated pressure increment is compared with corresponding experimental results.
For single-phase cases, results show considerable differences compared to experiments, which may be partially due to neglecting leakage losses in CFD simulations. When the two-phase simulation is conducted, it is confirmed that the solver takes oil and water as dispersion instead of emulsion, for which rheological behavior is not reflected. This is because the solver is based on two sets of Navier-Stokes equations for each phase. Consequently, the better approach for simulating the emulsion flow in ESPs by CFD methodology is to assume a single-phase, pseudo-homogeneous fluid with the rheology depending on the oil and water fractions and properties.