bluuebunny/crossref_metadata_2025 huggingface dataset:
Sedimentological, Diagenetic, Petrophysical Controls on the Miocene Submarine Deposits, Gulf of Suez: Implications for Reservoir Quality
Authors: Abdelhalim Kareem B. , Radwan Ahmed E. , Abdelfattah Tharwat A. , Shabaan Mohammed N. , Elkhawaga Mohammed A. , Kassem Ahmed A.
Published: October 2022

The Gulf of Suez Miocene ASL Member is an important reservoir for hydrocarbon development. This study specifically focused on the sedimentological, diagenetic, and petrophysical characteristics to better delineate the reservoir quality variability. The data comprised of well logs from four (4) wells, two of which had whole core with a total length of 150 ft. About 65 rock samples were selected and made into thin sections. These thin sections were examined under a polarizing microscope to observe mineralogical composition and diagenetic evolution. X-Ray diffraction (XRD), scanning electron microscope (SEM), and core plug porosity and permeability analysis were performed and used to interpret the mineralogical composition, pore throat geometries, and pore system characteristics of the reservoir zone. The comprehensive analysis showed that the ASL Member was deposited as turbidities and gravity flows in a submarine fan system. Two closer siliciclastic sources, Wadi Baba and Wadi Feiran, are interpreted to be potential sediment sources that fed coarser siliciclastic material via submarine canyons and relay ramps between extensional faults. The petrophysical measurements showed clear reservoir heterogeneity with a range of porosities between 2 to 10 %, and permeabilities between 0.4 and 60 mD. The reservoir quality is influenced by sedimentation and diagenesis, which play a major role in enhancing or reducing the reservoir quality. Combining the sedimentological and petrophysical analysis will help identify sweet spots by delineating high quality reservoir fairways. The presented work provides a reference for depositional, diagenetic, and petrophyiscial controls on submarine fan depositional systems in the studied basin and elsewhere.
Elastic Full Wavefield Inversion: The Benefits and the Challenges in Clastic and Subsalt Setting
Authors: Baumstein Anatoly , Routh Partha , Basler-Reeder Kyle , Ho Cha Young , Tang David , Barr Jay , Martinez Alex
Published: October 2022

The main focus of our work is application of visco-elastic Full Waveform Inversion (eFWI) to estimation of elastic parameters directly from seismic shot data. In particular, we aim to recover the ratio between pressure wave velocity Vp and shear wave velocity Vs, which can be indicative of the type of fluid present in a potential subsurface reservoir.

The workflow we describe does not directly use well ties for wavelet control, as is typical in seismic inversion. We provide intuitive explanations for choices behind the proposed multi-stage hierarchical algorithm, outline its key steps, and present field data examples from a structurally simple clastic setting and a complex sub-salt environment. The latter, in particular, makes differentiating net versus non-net in pre-salt carbonate reservoirs a challenging problem when using narrow azimuth streamer data. The challenges include significant illumination variability caused by complex geometries of the evaporites, complex wave modes and scattering caused by strong property contrasts in the evaporites and carbonates, and layering of anhydrite and other salts within the evaporites causing complex transmission losses. The thick carbonate reservoir units beneath the salt further complicate the estimation process due to lack of low frequency signal recorded in streamer data.

Our methodology shows that it is possible to directly invert shot data to obtain geologically meaningful elastic properties that can be useful in exploration and early development phases. However, challenges remain. We demonstrate that inverted acoustic impedance (Ip) from eFWI has higher fidelity and more reliable magnitude compared to the ratio between compressional and shear wave propagation speeds (Vp/Vs). In fact, the former is sufficiently accurate to be reliably used for porosity prediction. In turn, eFWI Vp/Vs inversion results are in qualitative agreement with well information (as a blind test) for the clastic example and able to discriminate the net versus non-net for the pre-salt example without well information. However, the quantitative match may be insufficient to determine the type of fluid via rock property inversion without any well control. Further research is needed to investigate the sensitivity of Vp/Vs and determine if the quality of the data is key a factor, in addition to stabilizing simultaneous extraction of several elastic parameters from seismic data via constrained inversion framework.
Automated Well Location Optimization Using Wish Technology
Authors: Motlagh Masoud , Thenon Arthur , Ismail Ahmed , Eberle Nicolas , Bergey Pierre
Published: October 2022

To optimize the value of the ADNOC future development, subsurface optimization opportunities in several reservoirs under development (Shuaiba, Lekhwair-3, Kharaib-2 and Kharaib-1) are investigated. The Shuaiba reservoir is the major contributor to field production, with three main different areas: North, Center and South. This paper presents the application of the WISH tool and associated workflow to optimize the location of significant number of both producer and water injection new wells in central and northern units.

WISH (Well Improvement ScHeme) is an automated Generative Design method and tool developed by TotalEnergies to improve well pattern designs. The approach balances the importance of several positioning rules to generate potentially performing candidate patterns. Commonly accepted positioning rules are suggested (e.g.: positioning wells away from undesired fluids, in rich areas, etc.) and can be mixed with custom positioning rules designed by the engineer (e.g.: positioning wells in good history-matched areas, etc.). These patterns are evaluated using conventional dynamic reservoir simulations. Optimization methods like Design of Experiments can be utilized to identify faster and better patterns compared to traditional approaches.

By sequentially optimizing the location of injectors and then producers, it demonstrates that up to 170 mmbbl of additional reserves and 3 years of extended plateau could be achieved. Number of injectors remains the same but the injection and sweep strategy changes significantly. Number of producers however could be reduced by 45% to 60% with different economical outputs respectively (higher reserve/lower NPV).

The paper will strengthen the literature corpus relative to benefits of introducing physics driven well placement heuristics in Computer Assisted Design well design processes by showing results of a complex real-life application. The process is applicable on single or multi-realization models (considering uncertainties). Thanks to the intuitive nature of WISH design rules, human easily keep control of overall optimization during the exploration loops. Performing patterns are identified in looping processes involving comparatively few simulations.
Delineating Karst, Fault and Fractures Interpretation Through Integration of Seismic Attributes and Diffraction Imaging in Giant Offshore Field Abu Dhabi
Authors: Goraya Yassar , Alfelasi Ali Saeed , Inoue Hiroyuki , Al Hmoudi Amna Rashid , Yingpeng Chen , Xiaolin Lyu , Albeshr Manal I.
Published: October 2022

Today, in a matured developed field, reservoir management is challenging due to poor seismic resolution at reservoir level. Whereas overburden geology further deteriorate seismic quality due to foot prints, observed at reservoir level. Overburden geology is a key challenge for reservoir characterization and may mislead faults and fractures interpretation, identification of rock properties and distribution of fluids. In this paper we tried to integrate both diffraction and reflection data to improve seismic resolution to delineate reservoirs and non-reservoirs zone with drilling and well data.

Seismic data

Seismic data was acquired using OBC technique. PreStack Time Migration processing was performed in 2002, 2016 and psdm migration was performed in 2018 for structural interpretation. However data quality for reservoir characterization was affected by the hardness of the seafloor and anomalies in the overburden. These challenges are currently being addressed through diffraction imaging.

In 2022, Diffraction imaging is performed for 10×10 KM2 pilot area, due to which we were able to delineate karstic feature in detail and faults at reservoir.
Sedimentary Characters and Flow Transitions of Reworked Carbonates: A Case Study of Cenomanian-Turonian Reworked Sediments in the Eastern Abu Dhabi, UAE
Authors: Shimomura Takahiro , Yamanaka Motoyoshi
Published: October 2022

Reworked carbonate caused by the major erosional event of the "Turonian Unconformity" is considered to be distributed around the eastern part of Abu Dhabi, UAE. During 2021-2022, new wells were drilled in a prospective area where the reworked carbonate was deposited. By using the new wells data (wireline logs and cores) and pre-existing wells data, we considered lateral changes in sedimentary character and flow transitions of the reworked carbonate.

We conducted a well-well correlation, based on the wireline logs (GR, Neutron, Density, Resistivity and Sonic) of a total of 5 wells which were drilled in the prospective area. To understand the spaciotemporal changes of the reworked carbonate facies and properties, we conducted core observation and description, and routine core analysis (porosity and permeability) for the new wells.

In addition, based on the distribution and flow direction of this reworked deposit, we considered the changes of flow regime towards the flow direction.

The result of the well-well correlation and seismic interpretation suggests that the wells penetrated the same reworked carbonate body. We can recognize the variety of grain size, sorting, sedimentary structure, and a degree of the bioturbation between the wells: poorly sorted coarse-grained to pebbly carbonate is dominant around the depositional up-dip side, and sharp based well-sorted grainstone with sedimentary structures (grading and lamination) is dominant around the depositional down-dip side, with bioturbation being more intense especially at the upper part of these grading beds. These sedimentary characters suggest that the flow regime changed towards the flow direction: dense flow at the depositional up-dip side and dilute flow at the down-dip side. In addition, several grading beds in the same indicate that the flow repeated several times.

Routine core analysis and log calculation (porosity and permeability) results suggest that the sediments in a middle body of the reworked sediments has better reservoir properties.

There is remaining exploration potential for this new play concept (reworked carbonate reservoir) around Abu Dhabi. In this time, we drilled new wells to confirm this new play concept, and we suppose that the knowledge of this study may have a big impact to the future exploration.
Integration of Computed Tomography Scanning and Nuclear Magnetic Resonance Results with Conventional Laboratory Test Data for Effective Reservoir Characterization
Authors: Shvalyuk Elizaveta , Tchistiakov Alexei , Spasennykh Mikhail
Published: October 2022

The paper suggests a new laboratory tests workflow, aimed at reservoir characterization and rock typing of a polimineral clastic formation, based on microstructural characteristics. The proposed approach is accompanied by a comparative study of various laboratory techniques, including CT, NMR, MICP, centrifuging, and thin section analysis. The methodology for combining quantitative porous medium characteristics, derived from these multi-scale tests is also provided.

The developed laboratory test program includes porosity and permeability measurements, capillary pressure, electrical resistivity, NMR and CT-scanning tests. For initial differentiation of samples based on porosity, permeability and irreducible water saturation, we applied methods of flow zone indicator (FZI) and Winland R35. Afterwards, we performed joint interpretation of FZI with the results of centrifuging, resistivity, NMR and CT-scanning tests. Finally, for the most representative samples from the rock types, defined at previous steps, we performed X-ray fluorescence spectroscopy, XRD, MICP and thin section analyses.

In our study, we applied FZI, calculated as a function of irreducible water and porosity. Compared to conventional FZI, derived from porosity and permeability, our approach enabled more reliable rock typing in both sandstones and low-permeable siltstones.

CT tests showed that within the distinguished 4 rock types grain and pore sizes increase from the 1st to the 4th rock types. CT-scanning and X-ray fluorescence spectroscopy detected presence of pyrite in all samples. Siltstones contain more pyrite than sandstones that reflects deeper marine and consequently more anoxic depositional environment.

The obtained NMR T2-spectra appeared to be effected by both porous medium and mineralogical composition. Pyrite inclusions caused shifting of the T2-spectra to lower values, while carbonate presence – to higher ones. Therefore, since NMR signal is effected by multiple factors, applying of a single T2cutoff value for reservoir characterization and rock typing can lead to ambiguous interpretation.

The proposed algorithm for combining quantitative parameters of the porous medium allowed integration of pore size distributions, derived from CT and capillary tests. This enabled characterization of the whole range of pore sizes covered only partly by the different methods. The resulted pore size distribution enabled calibrating NMR Т2 spectra and defining individual surface relaxivity values for each rock type.

The selected set of techniques allowed confident differentiation and characterization of the rock samples based on multiple parameters, which were interpreted in relationship with each other. Moreover, the developed methodology was verified by applying additional laboratory tests, which confirmed the results of the proposed rock typing and reservoir characterization.
Using Machine Learning to Capture High-Permeability Streaks in Reservoir Models
Authors: Singh Manish Kumar , Parra Humberto , El Jundi Obeida , Ben Jeddou Houcine , Kada Kloucha Chakib , Mustapha Hussein
Published: October 2022

Permeability modelling remains a major challenge in the reservoir modelling exercise. The main reason for this is the limited availability of measured input data and the effect of different geological processes on reservoir permeability. This leads to nonrepresentation of high-permeability streaks in the model. In this paper, we present a machine-learning (ML) driven approach that captures the permeability variation in the reservoir using available input data.

In ML, clustering is an unsupervised approach aimed at automatically grouping data with similar properties. We use several clustering techniques to automatically identify high-permeability data points by dividing data into groups, also known as clusters, and then choosing the cluster with the maximum permeability and assigning it a new rock type. For each rock type, we fit and evaluate many ML regression models, and show their outperformance over traditional fitting approaches. Porosity and several openhole log properties are used as input for the regression models. By fixing porosity but varying the other properties, the variability of permeability values is predicted.

Clustering, using ‘K-Means’ ML algorithm, resulted in an efficient approach of automated high permeability identification. Several ML models were trained and evaluated, and the models with the minimum error scores, namely mean square error (MSE) and R Squared (R2), were chosen for further predictions. Random Forest was within the top models for a variety of rock types. In general, complex curve fitting using ML outperformed traditional fitting approaches (i.e., straight line fitting) and demonstrated high potential for accurate, automated, high-permeability identification and integration. The predicted permeability has been calibrated with well test permeability data.
CO2 Plume Detection Using Ras, Temperature and Noise Tools in A CO2 WAG Reservoir
Authors: Igogo Arit , Hutajulu Astia , Mohamed Sallam Yassin Farouk , Khan Sara Hasrat , Bhushan Yatindra , Al Ali Mona Yousif , AlSeiari Reem Ali Mabkhout , Aidroos Alwahedi Mohamed Abdulhameed , Al Hammadi Shareefa Ahmed , Al Teneji Aamna
Published: October 2022

In alignment with most company's vision to reduce greenhouse effects by expanding CO2 carbon capture and utilization for oil fields, CO2 gas is injected into the reservoir to enhance oil displacement and maintain reservoir pressure. Since CO2 gas is miscible in the oil, the gas flood front is not piston-like; the gas is slowly absorbed by the oil changing the oil properties. Detection of the CO2 plume is necessary to monitor CO2/ injected water/ oil distribution (at and away from the well) and to track the effectiveness of the complicated CO2 WAG injection process in terms of improved sweep efficiency.

Monitoring CO2 flood front movement requires a logging measurement that can distinguish oil from CO2 in the formation. This measurement must have a sufficiently large dynamic range for the change from no CO2 to a high CO2 saturation to be distinguished within measurement error. This paper highlights the utilization and integration of Reservoir Analysis System (RAS) and Noise tools in CO2 plume detection. It also highlights some of the limitations of the RAS tool in high water transition zone in CO2 WAG environment.

As the oil is push away from the injection well, the flood front will be characterized by oil having varying amounts of miscible CO2 gas dissolved in it. The rate and composition of the injection gas determines how much of the oil that will expand. The density of the oil may not change much (since the oil density is close to the CO2 gas density) but the hydrogen density of the oil will decrease considerably as is the case for CO2. Another factor that controls the CO2 plume movement is the stratigraphy of the heterogeneous carbonate reservoir – where the coarsening upwards trend of the facies associations of High Stand Systems Tract (HST) coupled with pervasive cementation, creates non-uniform movement of CO2 plume vertically and spatially.

Logging results shows Neutron porosity (PHIRN) and PNC near/far capture ratio are the preferred log measurement curves because they have the most sensitivity to the large decrease in hydrogen index when CO2 replaces oil or is dissolve in oil. Other curves like Ratio of Near to Long at Burst (RLNB), Long Inelastic Rate Sigma (LIRS), temperature and noise logs also play significant roles in CO2 plume indications.

The outcome of this study has helped understand the vertical and lateral extent of the CO2 WAG flood front, estimate saturations, evaluate the well integrity, and locate un-swept zones. Additionally, RAS data is hard data used as calibration (blind test) to check the robustness of the dynamic model.
The World's Largest Contiguous Onshore and Offshore 3D Seismic Survey is Getting Even Larger
Authors: Al Mesaabi Saif Ali , Cambois Guillaume Marie , Cowell James , Arnold David , Boukhanfra Mohamed Fawzi , Al Karbi Saeed Hamad , Mahgoub Mohamed
Published: October 2022

In late 2018 ADNOC launched the world's largest continuous seismic survey to cover the entire Abu Dhabi Emirate, onshore and offshore, with high-resolution and high-fold 3D seismic. In 2021 ADNOC started acquiring the remaining transition zone (TZ) area bridging the divide between land and sea. The onshore and offshore survey designs could not be repeated for the TZ survey design due to environmental difficulties and associated costs. Instead, we adopted a novel approach using uneven source spacing to secure some far-offset coverage but not as dense as near-offset coverage.

TZ acquisition started in July 2021 and is close to 35% complete at time of writing. The crew has performed according to plan and has met its rigorous HSE objectives while operating in very sensitive areas. The full TZ survey is smaller than the onshore and offshore areas, but it is without a doubt the most difficult part of this entire project. We expect completion in 2024.

This transition zone survey uses an innovative design and the first offshore nodes with MEMS sensors. It is also the largest nodal TZ operation ever conducted.
Delivered the First Maximum Reservoir Contact Well in Giant Mature Field Using Source-Less LWD Technology; Case Study, Onshore Abu Dhabi
Authors: Holmquist Andrei , Thakur Parmanand , Barragan Ernesto , Bazuhair Mohamed , Pandey Vikram Kumar , Singhal Sangeeta , Nazarbayev Nurbek , Fares Wael , Ghobashy Ahmed , Mubeen Muhammad
Published: October 2022

This case study well is in a mature onshore field, which has been under production for a long time (started in 1970) resulting in depletion of some of the reservoir units presenting challenges for optimizing drilling performance and managing risks associated with stuck-pipe incidents. Additional challenges are minimized surface footprint, 100% reservoir contact in thin targets and acquisition of accurate petrophysical data for formation evaluation. A detailed pre-well study was conducted utilizing historical field and nearby wells’ data in the planning phase with close collaboration in a multi-disciplinary team including well and Bottom Hole Assembly (BHA) design and pre-well modeling for geosteering and LWD tool string configuration taking into account the elimination of radioactive chemical sources. The pre-well study has concluded that the azimuthal deep propagation resistivity image is going to provide proactive geosteering solution to identify the approach to both top and bottom boundaries. The BHA has also included rotary steerable system (RSS) along with optimized Logging While Drilling technologies (LWD) which has included, high-resolution micro resistivity imaging, Laterolog resistivity, nuclear magnetic resonance (NMR), sonic caliper and near-bit gamma ray. Continuous real-time monitoring provided drilling performance monitoring and analysis as well as facilitating geosteering services. The 8,356 feet horizontal section was effectively geosteered with 100% reservoir contact tapping into two thin reservoir sub-layers. Real-time azimuthal deep propagation resistivity image/curves were used to geosteer the well trajectory precisely within target zones and provided 4-5 feet TVD detection to bed boundaries. Also, high-resolution microresistivity images, dip picks and near-bit azimuthal gamma ray helped in maintaining the well-bore attitude parallel to the stratigraphy within each sub-layer. This data facilitated a smooth transition from one sub-layer to the next with minimum borehole tortuosity aided by the push the-bit RSS and at-bit-inclination measurements.

In addition, NMR provided real-time porosity and permeability measurements assisting in well placement and enhancing reservoir understanding as well as optimizing future well planning workflows. This paper presents a step change from the traditional field development drilling techniques in terms of horizontal length. Similar well designs are currently being implemented in an effort to benchmark drilling, well placement and petrophysical data gathering requirements for future development drilling in order to maximize asset value.
Machine Learning Applications of 4D Seismic in Carbonate: Case Study Offshore Abu Dhabi
Authors: Mahgoub Mohamed Abdelghany , Bashir Yasir , Berry Andy Anderson
Published: October 2022

Seismic 4D analysis is a model for integrating different disciplines in the oil and gas industry, such as seismic, petrophysics, reservoir engineering, and production engineering. Two 3D seismic surveys were conducted in the studied area with low repeatability of the recordings: the baseline survey in 1994 and the monitoring survey in 2014. A full 4D seismic co-processing of the baseline and monitor surveys was performed for both surveys starting with the field tapes. The 4D seismic co-processing improved poor seismic acquisition repeatability and 4D seismic attributes such as NRMS and predictability showed that. 4D time-trace shift was also performed, using the baseline survey as a reference to measure the time shifts between the baseline survey and the monitor survey at 20-year intervals. Dynamic 4D trace warping was followed by seismic 4D inversion to compare the 4D difference in the seismic inverted data with the difference in seismic amplitude. The seismic inversion helped overcome noise, multiple contamination, and differences in dynamic amplitude range between the baseline and seismic monitoring measurements. Applications of machine learning in the geosciences are growing rapidly in both processing and seismic interpretation. We then examined the relationship between well logs and seismic volumes by predicting a volume of log properties at the well locations of the seismic volume. In this method, we computed a possibly nonlinear operator that can predict well logs based on the properties of the adjacent seismic data. We then tested the Deep Forward Neural Network (DFNN) on six wells to adequately train and validate the machine learning approach using baseline seismic inversion data and monitoring data. The objective of trying such a supervised machine learning approach was to predict the density and porosity of both the baseline seismic data and the monitoring seismic data to verify the accuracy of the 4D seismic inversion.
Characterization of Late Aptian Upper Shuaiba Sequences in Western Abu Dhabi Based on Newly Acquired 3D Seismic Data
Authors: Nag Arnab , Tokhi Barnali
Published: October 2022

The Shuaiba Formation, one of the primary reservoirs of Early Cretaceous Petroleum System, has been an important exploration target in onshore Abu Dhabi due to its excellent reservoir quality specifically along the platform margin. Initially the Bab Basin carbonate development was slow but increased during lowstand sequences of Upper Shuaiba which is also known as Shuaiba Sequence 5 (Strohmenger et al., 2010). The Upper Shuaiba is distinguished from Lower Shuaiba by the presence of clay, high frequency and low amplitude progradational sequences. This study is going to describe the nature of the carbonate development within these Upper Shuaiba sequences in western Abu Dhabi.

Newly acquired 3D seismic data, existing well data and regional information have been utilized for seismic interpretation and litho-facies analysis to characterize Shuaiba Sequence 5. These interpretations were then linked to the depositional processes which generated the geometries and distribution of facies.

Based on well correlations within the study area, the Bab shale is roughly 100ft near the Shuaiba platform. It forms a wedge on the slope of the platform and gradually thins out to ~17ft towards the north. The deposition of the shale is attributed to influx of terrigenous sediments during the lowstand, which were later distributed by longshore currents as inferred from seismic attribute maps. The occurrence of carbonate above the Bab shale has been related to the cessation of siliciclastic input, which created a suitable environment for a carbonate factory. Shallow water depth and frequent sea level fluctuations created several thin clinoform sequences. These fourth order sequences are observed to have an average thickness of ~20ms and are often restricted within two seismic reflectors. The orientation of the clinoforms is NW-SE. These are categorized into three sets as reported by previous authors (Pierson et al., 2010 & Whitcomb et al., 2021).

The clinoforms have higher amplitude in the top set, which gets dimmer in the bottomset. Lithofacies from core data show the presence of thin beds of floatstone to packstone at the topset, which could form potential reservoir subject to better permeability development. The overlying Nahr Umr shale is the regional seal. The clinoform sets are located over a NE-SW oriented structural trend and may form subtle traps due to updip facies change within the clinoforms. Similar type of strati-structural trapping mechanism could be found along the strike of these clinoform sequences and may become potential prospects for hydrocarbon exploration in western Abu Dhabi.
Innovative Solutions to Subsurface Challenges in Deep Hard Rock High Temperature Slim Wells
Authors: Wahshi Khalifa Omair , Thomas Boris Jean , Khaldi Saud Ali , Haji Younis Said , Salehi Yasir Mohammed , Yuan Roger Shihche , Mahrooqi Ali Khalfan , Harthy Khalid Nasser , Habsi Fahad Said
Published: October 2022

In this paper we present the challenges faced in one of PDO's onshore a deep (5200 mTVD) field. Among these challenges were hardness of the rocks, 40 ksi and a high temperature of 155ºC. Further, well bore instability, tectonic stresses and depletion. The time consumed to overcome these subsurface challenges with conventional drilling methods was affecting the economic attractiveness of some of the wells. A multi-disciplinary taskforce was established with the remit to improve overall well economics by overcoming field challenges and by turning some of the challenges into opportunities.

The working group identified opportunities across several themes that were deemed to have the highest impact on the well economics, well design and materials selections and new technologies. The introduction of a new design concept of (Fast Degradation Brine) in the annulus allowed a reduction of the brine weight after cementing the completion. This change enabled passing specific casing design burst loads associated with the reduction of the 7" liner weight from 35 to 29 ppf. This allowed drilling larger hole sizes of 6" and 6 1/8" instead of 5 7/8". H2S fugacity concept was used instead of the conventional partial pressure concept to evaluate the sour severity of the materials. In new technologies, Motorised Reamer Shoe (MSR) drive system, was piloted for the first time in PDO's cemented completion to enable re-drilling and reaming ledges and hole closure caused by tectonic stresses during the completion run. A Polymer Borate System (PBS) plug has proven to be an effective new technology, used as lost circulation material for dealing with severe losses in PDO.

Through introduction of new well design concepts, new technologies and new ways of working we managed to: - Safeguard reserves and enable full access to target reservoirs by overcoming drilling challenges through improvements in the well design. - Realise a 40%-well delivery time reduction, coupled with a significant reduction in NPT. - 30%-reduction in average well cost. - Realise cost saving of 2.9% through well design optimisations. We managed to safeguard production which would be lost in case of short landing the completion. - Replicate MSR technology on planned side-tracks in PDO's wells, and we are planning to apply this technology in horizontal wells. The technology will also be an enabler to further slim down well designs in other fields. - Put in place a replication plan for applying the H2S fugacity concept wherever applicable. The well design concepts and new technologies mentioned above are novel or new to PDO.
De-Risking Cavings by Coupling Spalling Rate and Numerical Geomechanics Modeling
Authors: AlBahrani Hussain , Alqam Mohammad , Makrami Adnan
Published: October 2022

Wellbore instability is a major cause of stuck-pipe incidents. Wellbore enlargements induced by instability work to produce enlarged rock fragments known as cavings. These fragments can overwhelm the rig hydraulics system, which can potentially lead to tight spots, overfill, stuck-pipe, and even loss of well. Therefore, it is essential to manage, prevent, or anticipate the production of cavings through reliable modeling techniques. Conventional geomechanics models can predict yielding and rock failure through a fitted failure criterion. This failure assessment does not offer a prediction of size or quantity of cavings that can be introduced to the wellbore. This is because failed rock, as predicted by a conventional geomechanics model, will not necessary dis-integrate and fall off into the wellbore. To overcome this blind spot, a numerical geomechanics model is coupled with spalling rate analysis.

The analysis is carried out using a 3D poro-elasto-plastic finite element model (FEM). The FEM uses offset wells data along with the best fitting failure criterion to estimate the wellbore instability limit. The considered offset wells data used consist of wireline logs, drilling reports, and mechanical testing lab results belonging to the formation of interest. The model uses this data to estimate the stress distribution and define the best fitting failure criterion. The model is then coupled with spalling rate analysis. This relies on hollow cylinder tests, which are conducted on cores extracted from the formation of interest, to determine the spalling criterion. The end result is prediction of quantities and sizes of cavings that will be introduced into the wellbore under the specified conditions.

Coupling spalling rate analysis with the 3D FEM model makes way for de-risking cavings production. It is shown that by applying different controls, such as the mud weight and its rheological properties, instability related challenges can be overcome within the means of the rig hydraulics system. It is also shown that at different values of mud weight, the quantities and sizes of cavings can be constrained in a manner that would allow the well hydraulics to manage them. Finally, the results make a clear distinction between yielded or failed rock, as decided by the failure criterion, and spalled or damaged rock, which will be introduced into the wellbore as caving fragments.

The coupled modeling approach presented in this work amplifies the impact of geomechanics analysis on drilling operations. This is done by not limiting the geomechanics modeling recommendations and output to mud weight only, but other controls within the rig hydraulics system.
Navigate Narrow Pressure Windows with Superior Performance and Minimal Risk Using Flat Rheology Oil-Based Drilling Fluids
Authors: Olivares Tulio Daniel , Al-Zahrani Walid , Anioke Chidiebere , Sultan Aldarini Wafa Saeed
Published: October 2022

The objective of this paper is to present the added value and superior performance of Flat Rheology Oil-Based Drilling Fluid (FROBDF) utilization across Narrow Pressure Windows and very challenging wellbore stability conditions. The FROBDF was able to mitigate the high potential chances of induced losses, wellbore collapse and resulted in reduced non-productive time (NPT) associated with successful trips, liner runs, barite sagging avoidance and no wellbore stability issues. Multiple formulations were evaluated during the design of the low pressure-impact FROBDF to meet operation requirements. Extensive tests were done in the lab with different sized bridging materials and wellbore stabilizers to overcome the expected challenges. Also, various contamination test including, drill solids, seawater, cement and acid gases contamination test were performed to understand fluids’ behavior and tolerance to various contamination. The results demonstrate high tolerance to most contaminations, the performance of the fluid was maintained without any major impact in fluid properties. Furthermore, key performance indicators (KPI) were stablished for field applications and was demonstrated the superior performance of FROBDF. Field applications were executed with the customized FROBDF formulation and demonstrated that the Low-pressure impact flat rheology drilling fluid reduced the effect of temperature on the fluid rheological properties and minimized the risk of induced formation losses. These same rheological features reduced non-productive time (NPT) associated with liner runs and barite sagging (maintained sag factor at 0.509). Reduced frequency of tandem sweeps pumping. With the proposed bridging strategy wellbore stability was achieved during the whole drilling and tripping phase of the well. In addition to that, after 64 hours under static conditions with 1,500 psi overbalance, no stuck pipe incidents, no loss circulation incidents, no excessive pressures recorded with low dilution and product consumption rate while maintaining flat rheologic profile below 30% variance across a different temperature range of 60°F, 80°F, 120°F and 150°F while drilling.

The drilling industry with the current worldwide oil situation is continuously looking for non-productive time reduction strategies, this low pressure-impact high performance non-aqueous drilling fluid is an effective solution designed to extend the critical drilling narrow window. This innovative technology is non-progressive gel structure that reduces hydraulic impact, optimizing low-shear-rate viscosity improves hole cleaning without generating excessive pressures in the circulating system. This allows for optimal rates of penetration in those challenging conditions.
Drilling Operations Real-Time Monitoring and Alerting Using Advanced Machine Learning Algorithms
Authors: Alzahrani Majed A , Alotaibi Bader M , Aman Beshir
Published: October 2022

Well construction is a lengthy, complex and an expensive process. A drilling rig can spend several months to complete the operation in a single well. When analyzing the type of operations performed by rigs, we can see that almost 30% of the time is consumed while making new hole (i.e., drilling time), while the majority of the rig time represents what is called the flat time. Any optimization of flat time can significantly reduce the well construction cost.

Flat time is a group of operation types that involve no drilling operations, such as BHA making, drill pipe tripping, hole conditioning, casing running, cementing, etc. For instance, the performance of two specific types of these operations is only determined by rig crew and rig capabilities, and is not influenced by hole condition or formation related factors. These operations are the drill pipe tripping in cased hole (DPTCH) and the drill pipe connection operations (CONN). In typical well construction operations, the DPTCH and CONN operations represent 30% and 20% of the flat time, respectively.

In this paper, we discuss the potential benefits of developing and deploying an automated solution to monitor and alert the performance of these two operations in real time. The paper will explain how the solution can employ advanced machine learning (ML) algorithms to process rig operation sensor data and realize rig states. Then, we discuss the impact on the operation when applying this solution to optimize the DPTCH and CONN operations.

A developed solution of real-time monitoring and alerting can contribute to a significant time and cost savings. It also can improve early warning signs and detection of operation troubles. Also, it can be the foundation of many real-time operation optimization solutions.
Benefits of Hydraulic Jet Pump for Unloading a Well Over Conventional Nitrogen Lift Method
Authors: Azeez Kamaran , Abdelbary Marwan , Rehman Abid Ur
Published: October 2022

Removing fluid from a wellbore column, allowing a well to flow initially, or bringing a previous well back online, nitrogen lifting is commonly used in north Iraq wells. Due to the inability of coiled tubing units to be delivered on time and their high cost, operators are forced to seek for an alternative method of unloading drilling fluid. A hydraulic Jet Pump is a technology used to complete the task.

A newly drilled well DB-H was chosen, and the drilling fluid volume calculated was 12,000 bbl. to pump to the surface and begin production, assuming nonstop operation between unloading and producing. The deployment of the hydraulic lift Jet Pump for both stages was planned. Well data from the operator was collected, the process design was initiated, and Jet Evaluation Modeling Software (JEMS) was used to run the design models. A Proper pump size was set up based on available data to meet operator expectations. A Reverse Circulating Jet Pump (RCJP) was chosen to be installed inside a Sliding Sleeve Door (SSD) at a depth of 2,450 ft using a slickline. injecting power fluid with a discharge pressure of 1,500 psi and a flow rate of 1.11 bbl per minute through the casing-tubing annulus and getting the return from 3.5-in tubing. Cleanup process, and production achieved in one run time.

Within the first three days of operation, the well had produced double than expected. The operating parameters of the surface unit were adjusted and well tested. Data acquisitions consisted of collecting samples to read the properties of oil and fluids. After ten days of continuous well offloading and producing, the operator decided to pull out the downhole memory gauge to collect real data and see how the well performance behavior changed with the jet pump operating. New data was gathered, and the jet pump operation was resumed. Operating parameters were tuned to achieve the production target (at 1,700 psi injection pressure and 1,690 BPD injection rate), and the net return was 1,300 BPD with 0.4 percent BSW.

This paper explains in detail the operation that saved the operator money and time by using an artificial lift to produce hydrocarbon from a specific well, which saved USD 300,000 at an early stage of cleanup and unloading the well. Increased production by 100 percent, generating $USD 3.5 million in monthly revenue in the production stage with the minimal cost of lifting.
Decision-Driven Subsurface Surrogate Model for Development Optimization Under Uncertainties
Authors: Li Jizhou , Shao Yufen , Zhu Yuzixuan , Furman Kevin
Published: October 2022

With ever-increasing complexity in Upstream project planning, to ensure decision quality, the dynamics of subsurface resources need to be embedded into concept screening to maintain consistency between the production forecast and development plan. We developed a decision-driven subsurface surrogate model that encapsulates key reservoir dynamics into the machine augmented mathematical technologies for holistic decision recommendation in concept selection and development planning under uncertainties. The surrogate model replicates the essential subsurface dynamics by using a hybrid-approach that takes into accounts both reservoir simulation data and physical first principle. In addition to standalone usage on production forecast for rapid profile screening under resource uncertainties, the subsurface surrogate model is incorporated into mathematical optimization models that simultaneously consider surface network, commercial obligation and project economics etc. to provide alternative concepts under various uncertainties. Our subsurface surrogate model has been applied for decision making on gas gathering system design, field development optimization, field-management timing and sequencing, and field tie-back study etc. Results not only show the capability of surrogate models to enable large scale rapid decision screening, but also bear a close resemblance between the predicted production profiles and the reservoir simulation results when fed with the field operating strategy recommended by our decision models with surrogate dynamics. The study demonstrates the reliability of our surrogate modeling technology on ensuring decision quality and helps build business’ confidence on technology adoption. By further incorporating subsurface uncertainties into surrogate models, the decision makers are provided with: probabilistic analysis of the outcomes, value of information analysis, cost of optionality and flexibility, and holistic project outlook etc. Our decision-driven surrogate modeling technology incorporated in mathematical decision models is the first of its kind for holistic decision support in concept selection and development planning in oil and gas industry, and has full potentials in a variety of asset lines with reliable subsurface performance prediction under uncertainties.
Blockchain in Oil and Gas Digital Fuel Passports – Protecting the Fuel Value Chain, Enabling New Business Models
Authors: Mueller Florian , Rudkovskaya Olga
Published: October 2022

The objective of this paper is to showcase how digital supply chain transparency solutions can be a key enabler for both certainty and new business models in today's value chains for both conventional and/or renewable fuel. In this context, we will discuss the pivotal role for the next decades to come of sustainability regulation - such as for example in the European Union's Green Deal - in setting the direction for all industry players involved. We will also consider the current (post-) pandemic crises currently unfolding which we believe will pose both challenges but also opportunities for established energy companies, especially with a view to adjacent and transitory business models.

For the fuel market, one key challenge will be a substantial increase in demand for renewable forms of fuel – be it in pure form or as a mix between conventional and renewable fuel; given the likely differential tax and regulatory treatment, there will be a need to unequivocally document the provenance, composition, and also tax-paid status of such fuels. This will require new forms of fuel assurance, involving both physical and digital solutions to address the two key topics: Fighting tax fraud and mislabelling: Proof of provenance and tax paid status - to protect the supply chain from infiltration of smuggled, non-tax paid, or fraudulently labelled fuel (renewable vs conventional origin)Mandatory reporting of sustainability related data: Proof of composition and quantification – enable accurate and trustworthy data on fuel composition (fully renewable, mix, conventional), as well as environmental footprinting – the latter being particularly important when dealing with bio- or renewable fuels that might require a verified carbon footprint and other relevant ESG/sustainability data

Based on this, we will introduce Digital Fuel Passports (DFPs) as a solution to address these points through one flexible and adaptable approach – leveraging an integrated solution consisting of industrial grade marking and inspection, as well as a robust digital supply chain traceability solution.
Investigation on corrosion behaviour of polymeric coatings on weathering steel under 3.5% NaCl Solution
Authors: Periasamy K , Manivannan S , Venkatesh R , Vivekanandan M
Published: October 2022

Construction of columns and bridges for sea transportation, where corrosion resistance is a major factor, is the most common use of weathering steel, it is a low carbon alloy steel. Under the correct environmental circumstances, weathering steel develops an adherent protective coating on its surface. Patina is the protective layer that develops on the surface of weathering steel. It protects against further corrosion occurring to the structure. Since these weathering steels are repeatedly exposed to a wet environment, their corrosion resistance decreases. Our research focuses on investigations of the coatings used on weathering steel to increase its corrosion resistance in marine conditions. The coatings applied on the substrate were poly urea, polyurethane, epoxy and black enamel. Immersion test, salt spray test and potentio-dynamic test were performed on the coated samples to determine how they would react to various conditions. The depth of the corrosion on the coatings was confirmed by the profilometry test. Based on corrosion tests, the conclusion that polyurea is the best coating, followed by polyurethane, black enamel, and epoxy, based on the corrosion studies.