bluuebunny/crossref_metadata_2025 huggingface dataset:
Asphaltene Mitigation in Giant Carbonate Abu Dhabi Fields: A Techno-Economic Comparison Between Continuous Injection and Formation Squeeze
Authors: Grutters Mark , Punnapala Sameer , Abdallah Dalia Salem , Cristea Zaharia , El Nagger Hossam El Din Mohamed , Anbumani Sivashankar , Sennad Rabah , Bakri Hasan Jamil
Published: December 2021

Asphaltene deposition is a serious and re-occurring flow assurance problem in several of the ADNOC onshore oilfields. Fluids are intrinsically unstable with respect to asphaltene precipitation, and operating conditions are such that severe deposition occurs in the wellbore. Wells in ADNOC are generally not equipped with downhole chemical injection lines for continuous inhibition, and protection of the wells require frequent shut-in and intervention by wireline and coiled tubing to inspect and clean up.

Since some of the mature fields are under EOR recovery strategies, like miscible hydrocarbon WAG and CO2 flood, which exacerbates the asphaltene precipitation and deposition problems, a more robust mitigation strategy is required. In this paper the results of two different mitigation strategies will be discussed; continuous injection of asphaltene inhibitor via a capillary line in the tubular and asphaltene inhibitor formation squeeze. Three asphaltene inhibitors from different suppliers were pre-qualified and selected for field trial. Each inhibitor was selected for a formation squeeze in both one horizontal and one vertical well, and one of the inhibitors was applied via thru-tubing capillary string.

The field trials showed that continuous injection in remote wells with no real-time surveillance options (e.g. gauges, flow meters) is technically challenging. The continuous injection trial via the capillary string was stopped due to technical challenges. From the six formation squeezes four were confirmed to be effective. Three out of fours squeezes significantly extended the production cycle, from approximately 1.4 to 6 times the normal uninhibited flow period. The most successful squeezes were in the vertical wells. The results of the trial were used to model the economic benefit of formation squeeze, compared to a ‘do-nothing’ approach where the wells are subject to shut-in and cleanup once the production rates drop below a threshold value. The model clearly indicates that the squeezes applied in ADNOC Onshore are only cost-effective if it extends the normal flow period by approximately three times. However, a net gain can be achieved already if the formation squeeze extends the flow cycle by 15 to 20%, due to reduction of shut-in days required for intervention. Therefore, the results in this paper illustrate that an asphaltene inhibitor formation squeeze can be an attractive mitigation strategy, both technically and economically.
Field Data and Laboratory Study to Investigate Water and Gas Injectivity and Cyclic Hysteresis in Miscible WAG Injection in Carbonate Reservoir
Authors: Masalmeh Shehadeh , Al-Keebali Aaesha , Igogo Arit
Published: December 2021

The objective of this paper is to investigate the water and gas injectivity in water alternating gas (WAG) projects using laboratory and field scale data. It has been reported in the literature that both gas and water mobility has been significantly reduced in three-phase flow compared to two-phase flow. This behaviour has been attributed to a cycle dependent hysteresis effect which reduced both gas and water mobility in the different injection cycles.

To address the gas and water injectivity and the cycle dependent hysteresis concept, the results of a detailed experimental program in addition to field injectivity data will be presented. The experimental program included three-phase experiments performed under reservoir conditions using live crude oil and carbonate reservoir core material. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir conditions and CO2 was used as miscible injectant. The field injectivity data is obtained from two CO2 WAG pilots in a carbonate reservoir.

The main conclusions of the study are: 1- Gas injectivity in the presence of mobile water is much lower than that in the absence of water, 2- Water injectivity in experiments starting with water cycle is better than that in experiments starting with gas cycle when compared at the same water saturation, 3- Cyclic hysteresis in gas relative permeability was observed when comparing the first and second gas cycle, however, no further hysteresis was observed in the subsequent gas injection cycles, 4- Cyclic hysteresis in water relative permeability was not observed, the injectivity was either the same or higher in the subsequent cycles. 5- The gas injectivity at similar gas saturation for experiments starting with gas is better than that for experiments starting with water, 6- Gas and water injectivity field data from ongoing CO2 WAG projects in carbonate reservoirs showed no cyclic hysteresis, the injectivity either the same or improved in the subsequent cycles, 7- The CO2 injectivity was lower than expected, in the same order as water injectivity, which could be due to injecting CO2 in high water saturation zone and 8) The low CO2 injectivity could have a positive impact on sweep efficiency and potential improvement of oil recovery.

This paper presents the results of a well-designed experimental program and field data from two CO2 WAG pilots to systematically investigate water and gas injectivity in miscible WAG projects in carbonate reservoirs. The paper provides a rich and rarely available set of experimental and field data that can help improve and optimize gas and WAG injection projects in carbonate reservoirs. Detailed analysis of the field gas and water injectivity data will be presented and discussed in-light of the laboratory experimental data.
Comparison of Psychological Distress, Life Satisfaction and Workplace Bullying Between Site and Office Workers in Oil and Gas Industry
Authors: Kusumawati Diah , Erwandi Dadan , Lestari Fatma , Kadir Abdul
Published: December 2021

In recent years, various industries become increasingly aware of the importance of mental health. Mental health is closely related to the management of psychosocial hazards in the workplace. The oil and gas industry is considered to be one of the laggards in the management of workers’ psychosocial hazards and mental health even though mental health is considered to affect workers’ health and operational safety. Workplace bullying is a phenomenon that can give adverse effects to individual workers and the organization. For workers, bullying can interfere with physical health, psychological stress, and satisfaction with life and work. This paper discusses prevalence of workplace bullying, psychological stress, and satisfaction with life of workers in the upstream oil and gas industry. The phenomenon experienced by workers on Sites is compared with the experience of the office workers in this paper, with no significant differences found between the incidence of bullying and satisfaction with life between the two populations. On the other hand, there is a significant difference in the psychological stress and chronic diseases reported by the respondents. Site workers experience higher psychological stress and more reported chronic health disorders than the office workers.
Pelican Lake: Learning From the Largest Polymer Flood Expansion in a Heavy Oil Field
Authors: Eric Delamaide
Published: December 2021

Polymer has been injected continuously since 2005-06 in the Pelican Lake field in Canada, starting with a pilot rapidly followed by an expansion. At some point, 900 horizontal wells were injecting 300,000 bbl/d of polymer solution and oil production related to polymer injection reached 65,000 bopd. As a result, the Pelican Lake polymer flood is the largest polymer flood in heavy oil in the world and the largest polymer flood using horizontal wells.

Although some papers have already been devoted to the initial polymer flood pilots, very little has been published on the expansion of the polymer flood and this is what this paper will focus on.

The paper will describe the various phases of the polymer flood expansion and their respective performances as well as discuss the specific challenges in the field including strong variations in oil viscosity (from 800 to over 10,000 cp), how irregular legacy well patterns were dealt with, and how primary, secondary and tertiary polymer injection compare. It will also show the performances of polymer injection in combination with multi-lateral wells and touch upon the surface issues including the facilities.

The availability of field and production data (which are public in Canada) combined with the variability in the field properties provide us with a wealth of data to better understand the performances of polymer flooding in heavy oil. This case study will benefit engineers and companies that are interested in polymer flood, in particular in heavy oil. The paper will be a significant addition to the literature where few large scale chemical EOR expansions are described.
Safety Net Model: Grid-Based HSE Risk Management Integration with Twin Orientations
Authors: Zhao Hongzhan , Yang Yifeng , He Xiaozhen
Published: December 2021

Although companies systematically introduce management systems to improve performance and reduce major accident risks, gaps remain. The mismatch between HSE management system and practical HSE works, line and HSE departments and HSE requirements and actions exerts significant negative impact on the effectiveness and efficiency of HSE management. Under these circumstances, operational management system (OMS), barrier management system (BMS), process safety management and asset integrity management are all studied and applied in an oilfield. The oilfield experienced nine years of development, and the production capacity increased from 4,000 to 400,000 barrels per day. Almost 7,000 people were working in the oilfield during peak time from around 40 countries. During such a development, HSE management was extremely challengeable, and a practical and integrated HSE risk management model was pursued and established.

This paper describes a method of HSE risk management integration called safety net model. The model physically segregates oilfield facilities into individually managed areas or grids. A safety grid is the basic unit of a safety net, and the safety net comprises a series of correlative and interactive safety grids from bottom to up. OMS, HEMP and BMS are the bases of safety net model. Each safety grid complies with the principle of twin orientations: the identification of HSE hazards and assessment of HSE risks and the formulation and substantiation of systematic risk control measures. Specifically, the safety grid has two sets of basic components: hazard, output and time (HOT) and authority, boundary and control (ABC). HOT refers to hazard orientation, and ABC refers to risk control orientation. Two sets of components define attributes of each safety grid. The risk profile is assessed for each grid, in which technical safety and consequence studies are introduced to visually represent at risk locations. Overlaying contours and process boundaries as typical examples result in a simplified model that enables area owners to recognise risks, controls and mitigations so that they can introduce suitable risk reduction measures for safe operations. Through components (HOT ABC) of each safety grid, OMS and BMS are introduced to operational sites and positions directly and easily. Six components are connection points of every safety grid, and all safety grids are knitted to an integrated safety net.

The implementation of safety net model contributes to good HSE performance of the oilfield studied, and the resulting performance is recognised and appreciated by local government and funding parties.

This paper focuses on how to communicate the information in compliance with the principle of twin orientations from safety studies recorded in OMS and BMS to the safety grid. Comprising safety grids, safety net model is an applicable and practical carrier of integrated HSE risk management.
Machine Learning Application to CO2 Foam Rheology
Authors: Iskandarov Javad , Fanourgakis George , Alameri Waleed , Froudakis George , Karanikolos Georgios
Published: December 2021

Conventional foam modelling techniques require tuning of too many parameters and long computational time in order to provide accurate predictions. Therefore, there is a need for alternative methodologies for the efficient and reliable prediction of the foams’ performance. Foams are susceptible to various operational conditions and reservoir parameters. This research aims to apply machine learning (ML) algorithms to experimental data in order to correlate important affecting parameters to foam rheology. In this way, optimum operational conditions for CO2 foam enhanced oil recovery (EOR) can be determined. In order to achieve that, five different ML algorithms were applied to experimental rheology data from various experimental studies. It was concluded that the Gradient Boosting (GB) algorithm could successfully fit the training data and give the most accurate predictions for unknown cases.
Fuel Ammonia from Fossil Energy: Hydrocarbon Utilization for Sustainable Development
Authors: Akai Takashi , Shimouchi Makoto , Miyoshi Keisuke , Okabe Hiroshi
Published: December 2021

Synthetic ammonia from fossil energy can technically be used for power generation. Viewed as hydrocarbon utilization, it enables oil and gas industries to move towards the sustainable development of resources while minimizing their carbon footprint. We present an integrated high-level overview of this concept by highlighting the following key aspects: i) the carbon footprint of the process, ii) the necessity for carbon capture and storage (CCS), iii) power generation from fuel ammonia, and iv) market development. First, the carbon footprint was estimated based on the chemical formulas of the process, which revealed the necessity for CCS for the process to provide cleaner energy. Second, having reviewed these four key aspects, we showed that most elemental technologies comprising this new value chain have already been technically proven. Finally, we discuss and conclude with possible ways towards the commercialization of this value chain.
First Successful Application of Casing in Casing CiC Refracturing Treatment in Shale Gas Well in China: Case Study
Authors: Liu Yaowen , Li Yuanzhao , Zhang Chi , Ming Yue , Xiao Jialin , Han Rong , Wang Zichao , Zhang Jiao , Wu Changhong
Published: December 2021

With active hydraulic fracturing performed since 2012, the Fuling shale gas field in China is one of the largest shale gas fields outside of North America. Recently, a Casing-in-Casing (CiC) refracturing treatment was successfully implemented, resulting in production beyond expectations. This was the first successful application of a CiC refracturing treatment in a horizontal shale gas well in this region, thus providing a new option for refracturing horizontal wells in China.

Bullheading diversion refracturing with diverting balls was previously attempted in this field with high initial production observed; however, production was inconsistent and quickly declined. Therefore, the operator decided to attempt a CiC refracturing method in an understimulated candidate well. This involved installing and cementing 3.5-in. casing in 5.5-in. casing to effectively isolate the perforations, which enabled plugging and perforating operations in the reconstructed wellbore for an effective refracturing treatment. A customized refracturing design integrated the production profile, residual recoverable reserves, and the specific 5.5- × 3.5-in. reconstructed wellbore limitation.

The length of the 3.5-in. casing was optimized to be as short as possible but still cover the original perforations, and high-performance slickwater was used to reduce pipe friction, thus increasing the treatment rate. An engineered breakdown approach was employed for improved fracture initiation. Additionally, more clusters were added between the original clusters and, based on production profile results, some of the original understimulated clusters with little proppant placement were reperforated. To overcome the impact of depleted fractures, a self-degradable particulate diverting agent was used to propagate new fractures, allowing access to new rock to increase total reserve recovery.

The treatment in the reconstructed wellbore was successful, with 21 stages fractured in 12 days, achieving 100% placement of the designed proppant and fluid. A treatment rate of 7 to 12 m3/min from the toe to heel was executed as designed. Test production of 183,800 m3/D was also achieved with a recovery rate of 88.1%. Production has remained consistent and wellhead pressure has remained steady at a high level throughout the first two months of production.

CiC refracturing technology helps overcome common disadvantages experienced with traditional refracturing techniques, such as poorly placed proppant and fluid and inconsistent production. CiC refracturing not only allows exploitation of bypassed reserves from original fractures, but also allows precise stimulation of new rock to obtain the highest reserve recovery. The successful implementation of this case study illustrates the reliability of CiC refracturing technology and provides valuable experience to be used during future regional horizontal well refracturing.
Geomechanical Approach in Classification of Borehole Failures in Fractured Carbonates of Boca De Jaruco Field
Authors: Norkina Anna Vladimirovna , Simakov Iaroslav Olegovich , Petrakov Yuriy Anatoljevich , Sobolev Alexey Evgenjevich , Petrashov Oleg Vladimirovich , Soloviev Alexey Vitalievich
Published: December 2021

This article is a continuation of the work on geomechanically calculations for optimizing the drilling of horizontal wells into the productive reservoir M at the Boca de Haruco field of the Republic of Cuba, presented in the article SPE-196897.

As part of the work, an assessment of the stress state and direction was carried out using geological and geophysical information, an analysis of the pressure behavior during steam injections, cross-dipole acoustics, as well as oriented caliper data in vertical wells.

After the completion of the first part of the work, the first horizontal wells were successfully drilled into the M formation. According to the recommendations, additional studies were carried out: core sampling and recording of micro-imager logging in the deviated sections.

Presence of wellbore failures at the inclined sections allowed to use the method of inverse in-situ stress modeling based on image logs interpretation.

The classification of wellbore failures by micro-imager logging: natural origin and violations of technogenic genesis is carried out. The type of breakout is defined. The result of the work was the determination of the stress state and horizontal stresses direction. In addition, the article is supplemented with the calculation of the maximum horizontal stress through the stress regime identifier factor.
Recovery Factor Improvement; A Success Story of Improving 10% of RF in Greater Natih Reservoirs, North of Oman
Authors: Sheibani Hilal , Wulandari Ratih , van Gilst Roeland , Al Lawati Hawraa , Abri Al Mutasem , Maqbali Humaid , Zaabi Fatma
Published: December 2021

Recovery Factor Improvement (RFI) is a process to check the hydrocarbon production efficiency by incorporating the actual static and dynamic field data, as well as the way how the field being operated. This has been a common process within Shell's portfolio since 2018 (Ref; Muggeridge et al., 2013 & Smalley et al., 2009). The approach has been developed to stimulate the identification of new opportunities to increase the recovery from the existing fields and to aid the maturation of these opportunities into the Opportunity Realization Process.

There are four (4) factors that affected overall reservoir recovery factor, they are: Pressure efficiency; related to which pressure can be reduced in the reservoir as dictated by the relevant facilities and wells.Drainage Efficiency; the proportion of the in-place hydrocarbon that is pressure-connected directly to at least one producing well on a production timescale.The "secondary pay" efficiency; takes into account the volumes of poorer quality rock in which the gas remains at pressure above the lowest pressure just outside the wellbore (Pf) when the reservoir is abandoned.Cut-off Efficiency; the proportion of hydrocarbon that is lost due to non-production of the tail.This approach was applied in the dry gas Natih Reservoir fields in the PDO concession area. Before the implementation of RFI, the average recovery factor for Natih was around 70%. This was considered low for a homogenous-dry gas reservoir. The targeted Natih fields were benchmarked against each other with a total of 11 fields with similar reservoir properties. Post the benchmarking exercise, the expected field recovery factor is approximately ~90-93%. The team managed to map out the opportunities to achieve the targeted RF and identified the road map activities. The activities are mainly related to: production optimization: retubing, re-stimulation reduce drainage: infill drilling, horizontal well reduce the field intake through compression

The outcome of the mapping was then further analyzed through integrated framework to be matured as a firm-project. The new proposed activities are expected to add around 9% additional recovery to the existing fields. There will be a remaining activities which will be studied in the future, example infill wells and intelligent completions. These will close the gap to TQ and add other addition RF of 11-13%.

As conclusion, the RFI was seen as a structured approach to better understanding the field recovery factor based on the integrated surface and subsurface data with a robust analysis to trigger opportunity identification linked to RFI elements. It is similar concept as sweating the asset by generating limit diagram for each recovery mechanism & the road map to achieve the maximum limit. This paper will highlight the Natih Fields RFI analysis, highlighting the key learning and challenges.
Smart Retarder for Cementing Systems with Accelerated Set and Gel Strength Properties with Potential for Improved Operational Safety
Authors: Rodrigues Klin , Dos Santos Auribel , Oskarsson Hans , Jankowski Szymon , Ferm Paul
Published: December 2021

Cement retarders available in the market include the traditional lignosulfonates and synthetic copolymers. Commonly, lignosulfonates lack batch to batch reproducibility which hinders formulation consistency. Both lignosulfonates and synthetic polymers will retard the set of cement. However, their chemistry dictates that they also slow down setting time which increases waiting on cement time, thus increasing rig costs. This paper proposes a new smart cement retarder that overcomes these traditional negatives.

A number of polymers were designed and synthesized aiming for a chemical able to retard the set of cement while also acting as an accelerator once the cement slurry was in place. These polymers were tested for cement retardation performance using a high-pressure high-temperature (HPHT) consistometer. Static Gel Strength Analyzers (SGSA) measurements were used to determine compressive strength development as well as static gel strength development while curing under downhole temperature and pressure conditions.

The new smart cement retarder delivers cement retardation in the 125 - 350°F temperature range and can be used at higher temperatures using a co-retarder. This unique material delivers an accelerated set and attains 500 psi compressive strength very quickly which minimizes waiting on cement time. In addition, this new retarder builds static gel strength rapidly and minimizes gel transition time. Upscaling to field application, the top of the cementing column takes the longest to set. By having this inbuilt accelerator into the system, it allows the top of the column to set as fast as possible gaining the needed compressive strength at the weakest point of the cement column. This should ensure the quality of the cement job in comparison with conventional retarders with significant operating cost savings.

The new smart cement retarder will simplify cementing formulations due to its flexibility in dosage range of the retarder within the slurry and improve the quality of the cement jobs. As a result, the proposed smart cement retarder can help with minimizing risk of failures during production and possibly improving safety.
Decarbonization and Improved Energy Efficiency Using a Novel Nanocomposite Surface Treatment
Authors: Nakatsuka Matthew , Marco Basile , Thapa Sumil , Ventura Alexander , Pascolini Osvaldo , Pellicciotta Luca , Veedu Vinod
Published: December 2021

Fouling of heat exchanger equipment through the formation and attachment of hard scale, microbially induced corrosion (MIC) products, or particulate erosion is a serious challenge to reliable production in the oil and gas industry. Exchangers which become fouled in this way perform 15-30% worse than their rated ability, requiring either constant intervention to clean away biofilms, continuous injection of biocides and corrosion inhibitors, or the regular plugging of tubes to prevent leaks, representing a significant operating expense and billions of dollars in lost production time.

When an exchanger is unable to provide sufficient heat due to tube fouling, additional sources of heating must be utilized to make up for this deficit and to ensure that facility processes remain within design allowances. This need for supplemental heating is a significant source of carbon emissions in the industry and represents a significant obstacle towards decarbonization efforts. However, it also represents an economically attractive way to simultaneously lower emissions while also lowering a producer's cost per barrel.

This work describes an alternate strategy to control and prevent fouling in heat exchangers, through the one-time application of an omniphobic (water- and oil-repelling) nano-surface treatment. Once applied to a heat exchanger, the extremely smooth and low-surface energy material greatly reduces the ability of MIC-causing bacteria to deposit and adhere to the surface. Because it imparts functionality to the surface itself, rather than simply function as a physical barrier, it enables long lasting protection which was validated under laboratory conditions in a pressurized autoclave, as well as two pilot demonstrations.

Results from both the laboratory and field evaluations of the treatment's promise showed that treated surfaces showed a corrosion rate over 36-times lower when compared to untreated surfaces, while also completely arresting the formation of corrosion pitting, tube fouling, and erosion of the tube interior. These field-validated results were then applied to the observed heating deficit of a proposed deployment site, resulting in calculated carbon emissions savings of up to 17,000 Tons CO2 per year.
Experiment on Mechanical Properties and Seepage Capability of Deep Tight Sandstone Under True-Triaxial Stresses Environment
Authors: Li Jiaying , Qi Chunyan , Gu Ye , Ye Yu , Zhao Jie
Published: December 2021

The characteristics of seepage capability and rock strain during reservoir depletion are important for reservoir recovery, which would significantly influence production strategy optimization. The Cretaceous deep natural gas reservoirs in Keshen Gasfield in Tarim Basin are mainly buried over 5000 m, featuring with ultra-low permeability, developed natural fractures and complex in-situ stress states. However, there is no comprehensive study on the variation of mechanical properties and seepage capability of this gas reservoir under in-situ stress conditions and most studies on stress-sensitivity are conducted under conventional triaxial or uniaxial stress conditions, which cannot truly represent in-situ stress environment. In this work, Cretaceous tight sandstone in Keshen Gasfield was tested under true-triaxial stresses conditions by an advanced geophysical imaging true-triaxial testing system to study the stress-sensitivity and anisotropy of rock stress-strain behavior, porosity and permeability.

Four groups of sandstone samples are prepared as the size of 80mm×80mm×80mm, three of which are artificially fractured with different angle (0°,15°，30°) to simulate hydraulic fracturing. The test results corresponding to different samples are compared to further reveal the influence of the fracture angle on rock mechanical properties and seepage capability. The samples are in elastic strain during reservoir depletion, showing an apparent correlation with fracture angles. The porosity decreases linearly with stress loading, where the decrease rate of effective porosity of fracture samples is significantly higher than that of intact samples. The permeabilities decrease exponentially and show significant anisotropy in different principal stress directions, especially in σH direction.

The mechanical properties and seepage capability of deep tight sandstone are successfully tested under true-triaxial stresses conditions in this work, which reveals the stress-sensitivity of anisotropic permeability, porosity and stress-strain behavior during gas production. The testing results proposed in this paper provides an innovative method to analyse rock mechanical and petrophysical properties and has profound significance on exploration and development of tight gas reservoir.
First Case Study for Litho-Petro-Elastic AVA Pre-Stack Inversion for Complex Tight Reservoirs Miocene – Upper Cretaceous in East Onshore Abu Dhabi
Authors: Obaid Khalid , Noufal Abdelwahab , Almessabi Abdulrahman , Abdelaal Atef , Elsadany Karim , Gofer Edan , Aly Omar , Nyein Glen , Mukherjee Anubrati
Published: December 2021

This study summarizes the efforts taken to provide reliable reservoir characterizations products to mitigate seismic interpretation challenges and delineation of the reservoirs. ADNOC has conducted seismic exploration activities to assess Miocene to Upper Cretaceous aged reservoirs in East Onshore Abu Dhabi. The Oligo-Miocene section comprises of interbedded salt (mainly halite), anhydrite, limestones and marls. Deposited in the foreland basin related to the Oman thrust-belt. Ranging in thickness from nearly 1.5 km in the depocenter to almost nil on the forebulge located to the west of the studied area.

The well data based geological model suggests that initially porous rocks (presumably grain-supported carbonates) encompassed polyphase sulfate cementation during recurrent subaerial exposure in which pores and grains were recrystallized sometimes completely too massive, tight anhydrite beds. This heterogeneity of the complex shallow section showing high variation of velocity impact seismic imaging, and interpretation to model the stratigraphic/structural framework and link it with reservoir characterization. Hence, ADNOC decided to conduct a trial on state-of-art technique Litho-Petro-Elastic (LPE) AVA Inversion to mitigate the seismic interpretation challenges and delineate the reservoirs.

The LPE AVA inversion provides a single-loop approach to reservoir characterization based on rock physics models and compaction trends, reducing the dependency on a detailed prior the low frequency model, Where the rock modelling and lithology classification are not separate steps but interact directly with the seismic AVO inversion for optimal estimates of lithologies and elastic properties. The LPE inversion scope requires seismic data conditioning such as CMP gathers de-noising, de-multiple, flattening and amplitude preservation, in addition to detailed log conditioning, petro-elastic and rock physics analysis to maximize the quality and value of the results.

The study proved that the LPE AVA Inversion can be used to guide seismic interpreters in mapping the structural framework in challenging seismic data, as it managed to improve the prospect evaluation.
Recent Case Histories of Multilateral Systems Enabling Thru Tubing Intervention in the Middle East
Authors: Butler Benjamin , Kelsey Matthew , Racine Baidy
Published: December 2021

Historically, the ability to perform intervention on multilateral wells has been limited. A lack of technologies pre 2010 with sufficient case histories and life of well reliability meant that generally multilateral well architecture was not selected in applications where thru tubing intervention was a requirement. In recent years, multilateral well architecture has continued to increase in demand, with more ML wells drilled and completed in the last five years than any other five-year period in the technology’s history. With this increased demand has come industry enthusiasm to further mature its intervention capabilities.

This paper will review two recent case histories of separate multilateral well completion systems that enable intervention. This opens up new potential for industry to take advantage of the cost reductions achieved with multilaterals in a much larger scope of well applications.

Two separate completion systems will be covered, system A in this paper installed in a cemented multilateral junction, and system B, a completion that creates a hydraulically isolated junction via a either a dual string completion or a single string completion that splits into two strings. These case histories were exectured in 2017 to 2019, and interventions were performed after one to two years of production.

Detailed in each case study will be an overview of the equipment, the operational sequence, intervention outcome, and any lessons learned or improvements.

The systems have demonstrated themselves a reliable method to access laterals in non-ideal downhole environments where debris is present after the well has been on production. The tubing sizes for the case studies is 3-1/2" and 4-1/2". In each of these wells, the following operations have been successfully performed: drift testing, acid stimulation through coil tubing and breaking of a ceramic disc. Both slickline and coil tubing have been used for the interventions and in some cases with tractors. Junction inclinations range from 1 to 43 degrees.

Plans for ongoing installations for the systems are being executed in the Middle East Region. Further, expansion of the system A capabilities by integrating it with other existing technologies is also planned. This will enable projects such as the installation of a trilateral well with flow control and intervention for each individual leg, and also the conversion of existing single bore wells to multilateral with intervention capability.
Transformer-Based Deep Learning Models for Well Log Processing and Quality Control by Modelling Global Dependence of the Complex Sequences
Authors: Kumar Ashutosh
Published: December 2021

A single well from any mature field produces approximately 1.7 million Measurement While Drilling (MWD) data points. We either use cross-correlation and covariance measurement, or Long Short-Term Memory (LSTM) based Deep Learning algorithms to diagnose long sequences of extremely noisy data. LSTM's context size of 200 tokens barely accounts for the entire depth. Proposed work develops application of Transformer-based Deep Learning algorithm to diagnose and predict events in complex sequences of well-log data.

Sequential models learn geological patterns and petrophysical trends to detect events across depths of well-log data. However, vanishing gradients, exploding gradients and the limits of convolutional filters, limit the diagnosis of ultra-deep wells in complex subsurface information. Vast number of operations required to detect events between two subsurface points at large separation limits them. Transformers-based Models (TbMs) rely on non-sequential modelling that uses self-attention to relate information from different positions in the sequence of well-log, allowing to create an end-to-end, non-sequential, parallel memory network. We use approximately 21 million data points from 21 wells of Volve for the experiment.

LSTMs, in addition to auto-regression (AR), autoregressive moving average (ARMA) and autoregressive integrated moving average (ARIMA) conventionally models the events in the time-series well-logs. However, complex global dependencies to detect events in heterogeneous subsurface are challenging for these sequence models. In the presented work we begin with one meter depth of data from Volve, an oil-field in the North Sea, and then proceed up to 1000 meters. Initially LSTMs and ARIMA models were acceptable, as depth increased beyond a few 100 meters their diagnosis started underperforming and a new methodology was required. TbMs have already outperformed several models in large sequences modelling for natural language processing tasks, thus they are very promising to model well-log data with very large depth separation. We scale features and labels according to the maximum and minimum value present in the training dataset and then use the sliding window to get training and evaluation data pairs from well-logs. Additional subsurface features were able to encode some information in the conventional sequential models, but the result did not compare significantly with the TbMs. TbMs achieved Root Mean Square Error of 0.27 on scale of (0-1) while diagnosing the depth up to 5000 meters.

This is the first paper to show successful application of Transformer-based deep learning models for well-log diagnosis. Presented model uses a self-attention mechanism to learn complex dependencies and non-linear events from the well-log data. Moreover, the experimental setting discussed in the paper will act as a generalized framework for data from ultra-deep wells and their extremely heterogeneous subsurface environment.
Case Study of a Novel Autonomous Real-Time Monitoring, Control and Analysis System, to Maximize Production Uptime on Sustained Annulus Pressure Wells, While Improving HSE and Compliance with Double Barrier Well Integrity Policies
Authors: Dsouza Rylan Paul , Cornwall Rachelle Christine , Brodie Alan David , Patela Pedro , Daghmouni Hamdi Bouali , Arakkalakkam Mohammad Hariz , Boni Venkata Praveen Kumar , Khan Asif Khan Haq Dad
Published: December 2021

This paper describes an innovative solution for the safe and effective management of wells with unplanned sustained annulus pressure (SAP). The solution restores double barrier integrity in the well and provides reliable real time annulus pressure and temperature data. It also has the functionality to autonomously bleed-off the annulus pressure at a pre-determined set point. As a result, the nature and severity of the SAP can be better understood, and in many cases wells that would otherwise have been closed in awaiting workover can remain in production.
Intelligent Well Drainage and Interference Density Analysis Tool for Optimizing Infill Drilling
Authors: Al-Sane Amal , Al-Bahar Mohammad A. , Bora Anup , Dhote Prashant S. , Nalla Gopi , Walker Jacob G. , Caicedo Vladimir
Published: December 2021

During the progressive development of mature fields, it is imperative to drill many infill wells to accelerate production and access bypassed oil. Optimizing the infill well spacing is always the concern to reduce interference with existing wells and improve recovery. In the present study, using intelligent data mining techniques, a new analysis and visualization tool has been developed and implemented to estimate and map drainage radius by well to assess the efficiency of the current development pattern and properly plan future wells. The tool deployed several performance-based techniques to estimate the contacted stock-tank oil initially in place (STOIIP) by each existing well, and outcomes can be compared between techniques for validation. The contacted STOIIP is then converted into an effective drainage radius by well using reservoir properties from the geo-cellular model.

The evaluated reservoir is subdivided vertically into pay zones drained by the wells based on geological barriers/baffles to flow and connectivity across the zones. The tool estimates drainage radii of the wells produced from the reservoir using five different methods. The resultant Proved Developed Producing (PDP) reserves polygon maps are generated for the connected zones. The drainage radii of wells with behind-casing opportunities are estimated based on correlation and adjacent wells methods, and Proved Developed Non-Producing (PDNP) reserves polygon maps were generated. Well interference density is estimated based on overlapping drainage radii polygons with adjacent well locations, which has then been validated with production and pressure data from the wells. This paper describes the methodology by which the well drainage radii and well interference density can be estimated and implemented on a selected reservoir.

This workflow can be successfully used to identify drained and undrained areas around the wellbore and opportunities for additional infill wells in the various pay zones of the reservoir. This exercise observed consistency in the drainage radii cumulative distribution from decline curve analysis methods and the No-Further-Activities (NFA) simulation case.
A Critical Literature Review on Rock Petrophysical Properties Estimation from Images Based on Direct Simulation and Machine Learning Techniques
Authors: Rizk Ahmed Samir , Tembely Moussa , AlAmeri Waleed , Al-Shalabi Emad W.
Published: December 2021

Estimation of petrophysical properties is essential for accurate reservoir predictions. In recent years, extensive work has been dedicated into training different machine-learning (ML) models to predict petrophysical properties of digital rock using dry rock images along with data from single-phase direct simulations, such as lattice Boltzmann method (LBM) and finite volume method (FVM). The objective of this paper is to present a comprehensive literature review on petrophysical properties estimation from dry rock images using different ML workflows and direct simulation methods. The review provides detailed comparison between different ML algorithms that have been used in the literature to estimate porosity, permeability, tortuosity, and effective diffusivity. In this paper, various ML workflows from the literature are screened and compared in terms of the training data set, the testing data set, the extracted features, the algorithms employed as well as their accuracy. A thorough description of the most commonly used algorithms is also provided to better understand the functionality of these algorithms to encode the relationship between the rock images and their respective petrophysical properties.

The review of various ML workflows for estimating rock petrophysical properties from dry images shows that models trained using features extracted from the image (physics-informed models) outperformed models trained on the dry images directly. In addition, certain tree-based ML algorithms, such as random forest, gradient boosting, and extreme gradient boosting can produce accurate predictions that are comparable to deep learning algorithms such as deep neural networks (DNNs) and convolutional neural networks (CNNs). To the best of our knowledge, this is the first work dedicated to exploring and comparing between different ML frameworks that have recently been used to accurately and efficiently estimate rock petrophysical properties from images. This work will enable other researchers to have a broad understanding about the topic and help in developing new ML workflows or further modifying exiting ones in order to improve the characterization of rock properties. Also, this comparison represents a guide to understand the performance and applicability of different ML algorithms. Moreover, the review helps the researchers in this area to cope with digital innovations in porous media characterization in this fourth industrial age – oil and gas 4.0.
Indications of Deep Marine Fans in the Early Miocene Foredeep of Lower Austria: A Potential New Play
Authors: Hinsch Ralph
Published: December 2021

The petroleum province in Lower Austria resulted from the Alpine collision and the subsequent formation of the Vienna Basin. OMV is active in this area since its foundation in 1956. Several plays have been successfully tested and produced in this complex geological region. The main exploration focus is currently on the deep plays. However, this paper proposes a so far unrecognized and therefore undrilled play in a shallower level to broaden OMV's portfolio in Austria.

Seismic re-interpretations of reprocessed 3D seismic data and structural reconstructions were used to review some of the existing plays and get novel ideas from improved understanding of processes. In the frontal accretion zone of the Alpine wedge, the Waschberg-Ždánice zone discoveries are limited to the frontal thrust unit and associated structures. The more internal parts of the thrust belt have only sparsely been drilled and are perceived not to have high-quality reservoir rocks.

The detailed structural interpretations indicated that the foredeep axis during the Early Miocene was positioned in the thrust sheet located directly in front of the advancing Alpine wedge (comprising the eroding Rhenodanubian Flysch in its frontal part). Seismic amplitude anomalies can be interpreted to represent Lower Miocene basin floor and slope fans. Nearby wells did not penetrate these fans but drilled instead shale-dominated lithologies. Thus, the presence of potential sand-rich fans in front of the advancing alpine wedge is considered a potential new play in Lower Austria. Analogues are found in Upper Austria some 250 km to the West, where several large gas fields in Lower Miocene deposits located in front of the advancing Alpine wedge have been discovered by another operator. In that area the fans are only partly involved in the fold-thrust belt. In Lower Austria, these fans are located within the rear thrust sheet(s), providing a structural component to a mixed structural-stratigraphic trap. Two potential charge mechanism can be considered: a) biogenic gas charge from the organic matter of surrounding shales (like the Upper Austria analogues) or b) oil charge via the thrust fault planes from the Jurassic Mikulov Formation (the proven main source rock in the broader area).

Our results add to the understanding of the Miocene structural-stratigraphic evolution of the Alpine collision zone. The definition of a potential new play may add significant value to OMV's upstream efforts in a very mature hydrocarbon province.