bluuebunny/crossref_metadata_2025 huggingface dataset:
Direct Visualization and Quantification of NCF-Strengthened CO2 Foam Generation, Propagation and Sweep in a 2D Heterogeneous Fracture Network Model
Authors: Wei Bing , Yang Qiong , Mao Runxue , Tian Qingtao , Wang Dianlin , Lu Jun
Published: September 2021

CO2 foam holds promising potential for conformance improvement and mobility reduction of CO2 injection in fractured systems. However, there still exists two main issues hampering its wide application and development, 1. Instability of CO2 foam lamellae under reservoir conditions, and 2. Uncertainties of foam flow in fracture systems. To address these two issues, we previously developed a series of functional nanocellulose materials to stabilize the CO2 foam (referred to NCF-st-CO2 foam), while the primary goal of this paper is to thoroughly elucidate foam generation, propagation and sweep of NCF-st-CO2 foam in fractured systems by using a self-designed visual heterogeneous fracture network. We found that NCF-st-CO2 foam produced noticeably greater pressure drop (ΔP) than CO2 foam during either co-injection (COI) or surfactant solution-alternating-gas (SAG) injection, and the threshold foam quality (fg*) was approximately 0.67. Foam generation was increased with total flow rate for CO2 foam and stayed constant for NCF-st-CO2 foam in fracture during COI. CO2 breakthrough occurred at high flow rates (>8 cm3/min). For SAG, large surfactant slug could prevent CO2 from early breakthrough and facilitate foaming in-situ. The increase in sweep efficiency by NCF-st-CO2 foam was observed near the producer for both COI and WAG, which was attributed to its better foaming capacity. Film division and behind mainly led to foam generation in the fracture model. Gravity segregation and override was insignificant during COI but became noticeable during SAG, which caused the sweep efficiency decreased by 3~9% at 1.0 fracture volume (FV) injected. Due to the enhanced foam film, the NCF-st-CO2 foam was able to mitigate gravitational effect, especially in the vicinity of producer.
The Role of CO2 in Carbonate Acidizing at the Field Scale – A Multi-Phase Perspective
Authors: Kumar Harish , Muhemmed Sajjaat , Nasr-El-Din Hisham
Published: September 2021

Most lab-scale acidizing experiments are performed in core samples with 100% water saturation conditions and at pore pressures around 1100 psi. However, this is seldom the case on the field, where different saturation conditions exist with high temperature and pressure conditions. Carbon-di-Oxide (CO2), a by-product evolved during the acidizing process, is long thought to behave inertly during the acidizing process. Recent investigations reveal that the presence of CO2 dynamically changes the behavior of wormhole patterns and acid efficiency.

A compositional simulation technique was adopted to understand the process thoroughly. A validated compositional numerical model capable of replicating acidizing experiments at the core-scale level, in fully aqueous environments described in published literature was utilized in this study. The numerical model was extended to a three-phase environment and applied at the field scale level to monitor and evaluate the impacts of evolved CO2 during the carbonate acidizing processes. Lessons learned from the lab-scale were tested at the field-scale scenario via a numerical model with radial coordinates.

Contrary to popular belief, high pore pressures of 1,000 psi and above are not sufficient to keep all the evolved CO2 in solution. The presence of CO2 as a separate phase hinders acid efficiency. The reach or extent of the evolved CO2 is shown to exist only near the damage zone and seldom penetrates the reservoir matrix. Based on the field scale model's predictions, this study warrants conducting acidizing experiments at the laboratory level, at precisely similar pressure, temperature, and salinity conditions faced in the near-wellbore region, and urges the application of compositional modeling techniques to account for CO2 evolution, while studying and predicting matrix acidizing jobs.
Development of a System for Remote Control and Monitoring of Wellheads
Authors: Kiplimo Elijah , Oyoo Daniel , Tapia Antonio , Jepng’etich Marseline
Published: September 2021

Wellheads have a major role in ensuring well integrity, providing access to the wellbore and flow control. It is vital to constantly monitor the wellhead fluid pressure and temperature effectively in order to maintain the full control of wellbore fluids. Over the years, wellheads have remained purely mechanical and have heavily relied on physical on-site monitoring. There is need to develop a reliable and accessible monitoring solutions for the wellheads in order to increase the effectiveness of the well integrity management systems and to get the full benefits of the wellhead data by incorporating the emerging data analytics technologies.

This project details the development of a system that gathers wellhead temperature, pressure and the accurate valve position at any given time. The data gathering systems used in this project entail smart sensor technology capable of withstanding the wellbore pressures and temperatures. The system transmits the data securely, using blockchain, to an online platform where advanced data analytics using MATLAB and machine learning algorithms are used for visual data representation. The online platform additionally provides a means of real-time valve position control and takes into account the exact revolutions required for the opening and closure of the valve hence keeping a record for maintenance purposes. The innovative use and analysis of the data gathered form the wellhead provides insights for the operators and service companies and gives a way for setting ang thresholds in order to get alerts based in their custom specifications. This paper documents the development of a system that gathers wellhead data and provides a means of remote control of the wellhead valves. It covers the design phase, selection of appropriate sensor placement locations on the wellhead, the design of valve actuators, offline data gathering systems and the online data analysis and valve control platform. The project also pays a key attention towards the secure data transmission techniques and highlights the benefits of incorporating such a system in the oil and gas upstream sector.
Rotary Fatigue Testing Device for Determining Drilling Fluid Compatibility in A Pdm Stator
Authors: McCalip Jonathan , Bohmer Bob , Daechsel Dustin , Zovko Andrea
Published: September 2021

The purpose of this study was to evolve the understanding between mud motor power section reliability and oil-based drilling fluid chemistry, using novel laboratory data recorded from a proprietary test apparatus and instrumentation. The underlying objective is driven by operator's desire to maximize drilling performance by extending the operating envelope of the PDM/drilling fluid system, beyond what is possible using legacy ASTM immersion testing.

This paper describes a new test method and machine, intended to complement currently existing test methodologies, that incorporates multiple interplaying downhole conditions. Twelve fluids were analyzed using the novel test machine and the results compared to data obtained from conventional ASTM immersion testing; The fluids varied with respect to base oil type, as well as concentrations of emulsifier, and wetting agent. The goal of testing was to determine if positive displacement motor (PDMs) elastomer failure mechanisms (abrasion, cracking, chunking) could be replicated in a controlled environment, and if doing so could improve the data and understanding of its lifespan in a PDM. The result of testing provided evidence of two and three body abrasion, compression set, chunking, and chemical swell. It was found that concentrations of additives, as well as base oil type significantly affect runtime in the novel test machine, even if the differences in conventional testing were inconclusive. The novel test machine demonstrated that concentrations of key additives, as well as base oil type significantly affect elastomer runtime, even if conventional testing showed inconclusive results.
Compressed Dimension of Reservoir Models Uncertainty Parameters for Optimized Model Calibration and History Matching Process
Authors: Al-Turki Ali , Alnajjar Obai , Baddourah Majdi , Moriwawon Babatunde
Published: September 2021

The algorithms and workflows have been developed to couple efficient model parameterization with stochastic, global optimization using a Multi-Objective Genetic Algorithm (MOGA) for global history matching, and coupled with an advanced workflow for streamline sensitivity-based inversion for fine-tuning. During parameterization the low-rank subsets of most influencing reservoir parameters are identified and propagated to MOGA to perform the field-level history match. Data misfits between the field historical data and simulation data are calculated with multiple realizations of reservoir models that quantify and capture reservoir uncertainty. Each generation of the optimization algorithms reduces the data misfit relative to the previous iteration. This iterative process continues until a satisfactory field-level history match is reached or there are no further improvements. The fine-tuning process of well-connectivity calibration is then performed with a streamlined sensitivity-based inversion algorithm to locally update the model to reduce well-level mismatch.

In this study, an application of the proposed algorithms and workflow is demonstrated for model calibration and history matching. The synthetic reservoir model used in this study is discretized into millions of grid cells with hundreds of producer and injector wells. It is designed to generate several decades of production and injection history to evaluate and demonstrate the workflow. In field-level history matching, reservoir rock properties (e.g., permeability, fault transmissibility, etc.) are parameterized to conduct the global match of pressure and production rates. Grid Connectivity Transform (GCT) was used and assessed to parameterize the reservoir properties. In addition, the convergence rate and history match quality of MOGA was assessed during the field (global) history matching. Also, the effectiveness of the streamline-based inversion was evaluated by quantifying the additional improvement in history matching quality per well.

The developed parametrization and optimization algorithms and workflows revealed the unique features of each of the algorithms for model calibration and history matching. This integrated workflow has successfully defined and carried uncertainty throughout the history matching process. Following the successful field-level history match, the well-level history matching was conducted using streamline sensitivity-based inversion, which further improved the history match quality and conditioned the model to historical production and injection data. In general, the workflow results in enhanced history match quality in a shorter turnaround time. The geological realism of the model is retained for robust prediction and development planning.
A Regression Model to Determine Pressure Ratings of Slotted Tubular Components With Imperfections
Authors: Remma Shravan Kumar , B.B. Devaiah , Deng Guijun
Published: September 2021

The objective of the present work is to develop a prediction model to predict the pressure rating accounting for the imperfections using Design of Experiments (DoE) approach. Each imperfection is modelled in terms of a design parameter and bounded by a certain realistic variation. The DoE approach aids in identifying the most influencing imperfections and in further developing an approximate model that relates the input design parameters to the maximum radial deformation. Furthermore, the regression model is built to obtain the pressure rating of the component accounting for the imperfections.

The study identifies that ovality and its orientation are by far the most influential imperfections when compared to others and provides the designer the effects of imperfection parameters on the component. The prediction model developed, serves as a ready reckoner to obtain the pressure rating of the component within the design space without any exclusive analysis. This approach leads to effective design and saves computational time.
Asphaltenes: Fundamental Principles to Oilfield Applications
Authors: Mullins Oliver , Pomerantz Andrew , Zhang Yunlong
Published: September 2021

The sophisticated molecular imaging methods, atomic force microscopy (AFM) and scanning tunneling microscopy (STM), have been utilized to image individual asphaltene molecules, both their atoms and bonds, and their electronic structure. The stunning images have confirmed previous results and have all but resolved the long-standing uncertainties regarding asphaltene molecular architecture. Asphaltenes are also known to have a strong propensity to aggregate. The dominante asphaltene molecular structure and hierarchical nanocolloidal structures have been resolved and codified in the Yen-Mullins model. Use of this model in a simple polymer solution theory has given the first equation of state (EoS) for asphaltene gradients in oilfield reservoirs, the Flory-Huggins-Zuo EoS. With this EoS it is now possible to address reservoir connectivity in new ways; equilibrated asphaltenes imply reservoir connectivity. For reservoirs with disequilibrium of contained fluids, there is often a fluid process occurring in geologic time that precludes equilibrium. The collection of processes leading to equilibrium and those that preclude equilibrium constitute a new technical discipline, reservoir fluid geodynamics (RFG). Several reservoirs are reviewed employing RFG evaluation of connectivity via asphaltene thermodynamics. RFG processes in reservoris often include diffusion, RFG models incorporating simple solution to the diffusion equation coupled with quasi-equilibrium with the FHZ EoS are shown to apply for timelines up to 50 million years, the age of charge in a reservoir. When gas (or condensates) diffuse into oil, the asphaltenes are destabilized and can convect to the base of the reservoir. Increasing asphaltene onset pressure as well as viscous oil and tar mats can be consequences. Depending on specifics of the process, either gooey tar or coal-like asphaltene deposits can form. In addition, the asphaltene structures illuminated by AFM are now being used to account for interfacial properties using simple thermodynamics. At long last, asphaltenes are no longer the enigmatic component of crude oil, instead the resolution of asphaltene structures and dynamics has led to new thermodynamic applications in reservoirs, the new discipline RFG, and a new understanding of tar mats.
Adaptation of Technologies Making Clean out Operations Environment Friendly and Cost Effective - Converting Failure into Success Using New Type of Fluidic Oscillator
Authors: Ahmed Barzan , Khoshnaw Farhad Abdulrahman , Raza Mustansar , Elmoneim Hossam , Shehzad Kamil , Sarbast Mustafa , Zanaty Omar El , Yousif Serwer
Published: September 2021

A case study is presented detailing the methodology used to perform the clean-out operation in a water disposal well of Khurmala Field, Kurdistan Region of Iraq. Untreated disposed water caused scaling and plugging in perforated liner and in the open hole that eventually ceased injection. Multiple attempts and investments were made in recent years to resume access to the injection zone using high-pressure hydro-jetting tools coupled with acid treatments. However, these attempts yielded futile efforts. Before proceeding with the decision of workover, it was decided to go for one final attempt to regain wellbore access using Fluidic Oscillator (SFO).

Fluidic Oscillator (SFO) having pulsing, cavitation and helix jetting action was used in combination with a train of fluids consisting of diesel, 28% HCl and gel. The clean out was performed in stages of 10m, to clean the fill from 1091m to 1170m. Since the well bore was initially isolated from the injection zone, the cleanout was conducted with non-nitrified fluids. As the cleanout progressed and access to the liner and open hole was regained, the circulation of insoluble fill to surface required a lighter carrying fluid. Nitrification, volume of the fluids, batch cycling, and ROP were designed considering the downhole dynamic changes expected during each stage of the operation.

The combination of SFO, the thorough selection of treatment fluids and the accurate downhole hydraulics simulations pertaining to different stages of the operation offered an effective solution and regained the connectivity between the wellbore and the injection zone. The injection rate of water increased from 0 bpm at 700 psi to 15 bpm at 200 psi. Throughout this operation, the SFO helix, cavitation, and acoustic pulse (alike) jetting proved to be more effective than other single acting rotating jetting tools. Also, Environmental impact was reduced by eliminating the need for a rig workover operation. The matching of the injection pressure when the well was first completed and the post job value indicated that the complete zone was exposed and scale deposits were removed from the critical matrix or bypassed.

SFO has an effective jetting near wellbore region, while the kinetic energy transferred via fluid makes the impact stronger in the deeper region. Internal mechanism of the tool allows it to handle high pumping rate and pressures, external finishing offer multi-port orientation of outflow that allows targeting the fill in desired directions. Presently the SFO used in the case study is the only technology that has pulse, cavitation, and helix jetting structure. Also, since the tool does not require redressing, it proves to be an efficient, safe and cost effective alternative
Incremental Method vs Split Conditions: Discussing the Similarities Between Reserves Evaluation and a Madoff Scheme
Authors: Salacz Dominique , Allam Farid , Szilagyi Imre , Mansoori Yousof Al
Published: September 2021

After the oil price crashes in 2014 & 2020 several M&A deals ended up in legal debates because operators cancelled major projects or infills wells that were booked in the "probable" reserves only. This document challenges the compatibility between the deterministic incremental reserve assessment method (PRMS2018, chapter 4.2.1.3), and the concept of split condition (PRMS2018 chapter 2.2.0.3), which is not allowed for reserves booking under PRMS. With a few examples, we explain why the incremental method may be misleading investors, if used wrongly.

Policies, stock market requirements, or simply the understanding of reserves guidelines may differ from one company to another. Many filers and auditors are still keen on using the deterministic incremental approach. This method consists in "defining discrete parts or segments of the accumulation that reflect high, best, and low confidence regarding the estimates of recoverable quantities under the defined development plan". In principle, this should give similar result to the widely accepted scenario method (PRMS2018, chapter 4.2.1.3) but in reality, major discrepancies are observed. Some reserve evaluation may also become misleading for banks, investors, or even for good asset management. I many cases, the estimation of recoverable volumes is reasonable, but it does not match the company CAPEX requirements, affecting corporate cash flow as well as potential Reserves Based Lending (RBL) requirements. In another case, the 1P case will be robust, but the 2P may be grossly overestimated, affecting M&A or share price.

"Reserves guidelines are principle based" this has recently become a very fashionable statement in the context of SEC bookings. Similar discussions will also occur when reviewing PRMS reports. However, different interpretations for keywords such as "Project", "Spit condition", or "FID" should not prevent the evaluator to provide a reliable reserves estimation to investor or company management.

This document questions the threshold where ethics disappears, and a Madoff scheme may become legal.
Diagnostic Plots of Pressure Transient, Rate-Transient, and Diagnostic Fracture-Injection/Falloff Tests
Authors: Craig David , Blasingame Thomas
Published: September 2021

All transient test interpretation methods rely on or utilize diagnostic plots for the identification of wellbore or fracture storage distortion, flow regimes, and other parameters (e.g., minimum horizontal stress). Although all "test" interpretations of interest are transient test data (i.e., those involving an "event"), the associated diagnostic plots are not interchangeable between such tests. The objective of this work is to clearly define the appropriate diagnostic plot(s) for each type of transient test.

The work applies the appropriate transient test theory to demonstrate the applicability of each diagnostic plot along with clearly defining the characteristic features that make a given plot "diagnostic." For pressure transient testing, the material is largely a review, but for rate transient tests and diagnostic fracture-injection/falloff tests, new ideas are introduced and documented to justify appropriate diagnostic plots. Data examples are provided for illustration and application.

In general, pressure transient test diagnostic plots are not misused, but the same cannot be said for diagnostic fracture-injection/falloff tests (or DFITs) where it is common to ascribe flow regimes and/or draw other erroneous conclusions based on observations from an inappropriately constructed or interpretated diagnostic plot. The examples provided illustrate both the correct diagnostic plot and interpretations, but also illustrate how data can be easily misinterpreted in common practice.
Core Competencies Identification and Development: Evidence from Oil and Gas Exploration Company
Authors: Vlasov Mikhail
Published: September 2021

Background

Key trends say that to stay as a primary energy source for the upcoming years Oil & Gas companies shall concentrate their efforts on efficiency and technologies, including digital. The situation in the Exploration sector is challenging, as there are almost no "easy" resources left to explore. One of the ways to build a further development strategy for the Oil & Gas Exploration Companies is to define and build development plans for their core internal capabilities. To boost their efficiency, companies shall concentrate their attention and efforts around their core competencies.

Purpose

The principal aim of this paper is to suggest the method of identifying the internal sources of competitive advantage (the core competencies of an organization) and building the plans of their development on the example of the selected Oil & Gas Exploration Company.

Methodology

A case study was carried out utilizing the methods synthesized by the author basing on the critical analysis of the previous conceptual and research studies, including strategic architecture, value chain analysis, POCCI model and both quantitative and qualitative methods. The identification of core competencies was based on a discussion nature of focus group activities organized in the form of strategic sessions among the top management level of the selected Company.

Findings

Five core competencies were identified for any Oil & Gas Exploration Company: managing personnel motivation and development, managing uncertainties, regional / basin analysis, building an integrated business-case, and geological modelling. These results were validated and proved by a crosscheck analysis, final discussions with the focus group and a round table discussion among industry experts, consultants and top managers of major oil companies.

Discussions and recommendations for further development

The validity of methods suggested by the author is proved, however, some points of further methodology were identified during the research. The clear understanding of internal capabilities, the core competencies development level and what is the company is capable of today and tends to be capable of in the future will become one of the most valuable parts in every strategic decision-support package. The clear picture of identified and estimated competences together with an on-going benchmarking becomes a valuable guide in systematization and managing the company's development.
Automating Wireline Perforation and Frac Plug Set Depths into Wellsite Reporting System Using a Time-Synchronous Digital Platform and IIOT
Authors: Van Buskirk Chad , Duncan Bob
Published: September 2021

During plug-and-perf zipper fracturing operations, the capture of incorrect perforation and frac plug depths plagues the future use of this data. Production models currently run on the assumptions of where stage boundaries and perforations should be - not using inputs of where they are. The entry points to the reservoir and stimulation schedule may have left considerable bypassed pay. These models may not require calibration, they simply required accurate data inputs from the onset - or better yet, on-the-fly corrections to access the entire pay zone.

A collaborative project started with an operator need to auto-import wireline perforation and frac plug setting depths into an industry recognized wellsite reporting software. The project then revealed itself to be much more – an exercise in ensuring quality depth data from site. This is a game-changing tool for service companies and operators alike. Unique automation capabilities were developed that unified several processes and IIOT data on a completions site.
Axial Fracture Initiation During Diagnostic Fracture Injection Tests and Its Consequences on Interpretations
Authors: Cai Yuzhe , Dahi Taleghani Arash , Wang Rui
Published: September 2021

Diagnostic fracture injection tests (DFIT) are used widely in the unconventional reservoirs to obtain formation properties. These properties can be crucial in optimizing primary and infill completions. The interpretation methods are assuming that pumping fluid would create a single planar fracture, however, perforation frictions and near wellbore stress concentration may accommodate initiation of fractures along the casing first (axial fractures). The possibility of the formation of an axial fracture increases in high injection rates and low differential stresses. In this study, we investigate the effect of the formation of an additional axial fracture on a DFIT test and its interpretation, using a fully coupled geomechanics and fluid flow model. We provide a model for the initiation and closure of axial and transverse fractures during the process. We also demonstrate that the estimate of the closure stress can be misleading when presence of an additional axial fracture is ignored. Finally, we discuss a potential method to determine the maximum horizontal stress under such circumstances. In fact, the variations in cement quality, cement type and its placement play roles in linking of adjacent perforations and form axial fractures, therefore it might be difficult to establish a safe perforation design to avoid initiation of axial fractures, but we can adjust our analysis to incorporate axial fractures effect.
Successfully Abandoning Wells with Extreme Corrosive Environment Using Mechanical Aids – A Case Study from South Iraq
Authors: Campana Barbosa Lucio Felipe , Iqbal Javaid , Bhaisora Devesh
Published: September 2021

Well abandonment under a corrosive environment is often unpredictable and challenging, especially if the zone exhibits irregular wellbore geometry due to severe corrosion. These situations not only increase associated risks, but also greatly increase the abandonment cost for workover operation. This paper presents a successful application of a mechanical aid to replace a firm base using bridge plug or viscous pill base to abandon a well in the province of Basra in Southern Iraq.

Numerous wells in Southern Iraq have compromised casing integrity due to sulphureous water flow from Umm Er-Radhuma / Tayarat formations, making their abandonment imperative. Due to unpredictable corrosion inside the casing, setting any type of mechanical bridge plug was a laborious operation, because the operator must run multiple logs to confirm the casing integrity and might not get the required casing integrity at the desired abandonment depth. Setting up a viscous pill was a challenge in the well environment, and in absence of a firm base it was highly probable that the cement plug would slump. Looking at multiple options to ensure the successful plug setting operation on the first attempt, it was decided to use a suitable mechanical aid, as a firm base to prevent the slumping motion of the fluids that were pumped to isolate sensitive zones. The unique foldable and adjustable parasol construction of the tool enabled it to be pumped through small diameter tubing avoiding any sticking, and it was a critical parameter for tool selection process.

This paper summarizes the first-successful well abandonment using such a tool in the province of Basra in 7-in. casing and 9 5/8-in. casing. The logging tool was not able to detect one section of 9 5/8-in casing, which was presumably completely corroded. The first attempt to isolate it using a polymer system was not successful, since the fluid flowed to different leaks in the outer casing. The parted 7-in. casing made it impossible to identify the depth of lower leaks. Then a plan to utilize the mechanical aid was presented and subsequently approved. Tool was dropped and set above the top of 7-in. casing and gave support to the first cement plug to abandon the well, significantly reducing the time and cost of abandonment of the well by reducing repeated plug jobs.

The use of the mechanical aid as a primary option to set plugs for abandonment purposes in corrosive environments has resulted in a great success by reducing non-productive time and enhancing zonal isolation results. Similar usages around the world will help in reducing workover operation economics where integrity of the casings is questionable.
A Novel Well Test Data Analyzer and Process Optimizer Using Artificial Intelligence and Machine Learning Techniques
Authors: Reddicharla Nagaraju , Rachapudi Subba Ramarao , Utama Indra , Khan Furqan Ahmed , Vanam Prabhker Reddy , Al Nuimi Saber Mubarak , Sultan Ali Mayada Ali
Published: September 2021

Well testing is one of the vital process as part of reservoir performance monitoring. As field matures with increase in number of well stock, testing becomes tedious job in terms of resources (MPFM and test separators) and this affect the production quota delivery. In addition, the test data validation and approval follow a business process that needs up to 10 days before to accept or reject the well tests. The volume of well tests conducted were almost 10,000 and out of them around 10 To 15 % of tests were rejected statistically per year. The objective of the paper is to develop a methodology to reduce well test rejections and timely raising the flag for operator intervention to recommence the well test.

This case study was applied in a mature field, which is producing for 40 years that has good volume of historical well test data is available. This paper discusses the development of a data driven Well test data analyzer and Optimizer supported by artificial intelligence (AI) for wells being tested using MPFM in two staged approach. The motivating idea is to ingest historical, real-time data, well model performance curve and prescribe the quality of the well test data to provide flag to operator on real time. The ML prediction results helps testing operations and can reduce the test acceptance turnaround timing drastically from 10 days to hours. In Second layer, an unsupervised model with historical data is helping to identify the parameters that affecting for rejection of the well test example duration of testing, choke size, GOR etc. The outcome from the modeling will be incorporated in updating the well test procedure and testing Philosophy. This approach is being under evaluation stage in one of the asset in ADNOC Onshore.

The results are expected to be reducing the well test rejection by at least 5 % that further optimize the resources required and improve the back allocation process. Furthermore, real time flagging of the test Quality will help in reduction of validation cycle from 10 days hours to improve the well testing cycle process. This methodology improves integrated reservoir management compliance of well testing requirements in asset where resources are limited. This methodology is envisioned to be integrated with full field digital oil field Implementation.

This is a novel approach to apply machine learning and artificial intelligence application to well testing. It maximizes the utilization of real-time data for creating advisory system that improve test data quality monitoring and timely decision-making to reduce the well test rejection.
Measurement of Cement in Situ Stresses and Mechanical Properties Without Cooling or Depressurization
Authors: Meng Meng , Frash Luke , Carey James , Li Wenfeng , Welch Nathan , Zhang Hongtao
Published: September 2021

Accurate characterization of oilwell cement mechanical properties is a prerequisite for maintaining long-term wellbore integrity. The drawback of the most widely used technique is unable to measure the mechanical property under in situ curing environment. We developed a high pressure and high temperature vessel that can hydrate cement under downhole conditions and directly measure its elastic modulus and Poisson's ratio at any interested time point without cooling or depressurization. The equipment has been validated by using water and a reasonable bulk modulus of 2.37 GPa was captured. Neat Class G cement was hydrated in this equipment for seven days under axial stress of 40 MPa, and an in situ measurement in the elastic range shows elastic modulus of 37.3 GPa and Poisson's ratio of 0.15. After that, the specimen was taken out from the vessel, and setted up in the triaxial compression platform. Under a similar confining pressure condition, elastic modulus was 23.6 GPa and Possion's ratio was 0.26. We also measured the properties of cement with the same batch of the slurry but cured under ambient conditions. The elastic modulus was 1.63 GPa, and Poisson's ratio was 0.085. Therefore, we found that the curing condition is significant to cement mechanical property, and the traditional cooling or depressurization method could provide mechanical properties that were quite different (50% difference) from the in situ measurement.
Phase Behaviour and Physical Properties of Dimethyl Ether DME/CO2/Water/Heavy Oil Systems under Reservoir Conditions
Authors: Huang Desheng , Li Yunlong , Yang Daoyong
Published: September 2021

In this paper, techniques have been developed to quantify phase behaviour and physical properties including phase boundaries, swelling factors, and phase volumes for reservoir fluids containing polar components from both experimental and theoretical aspects. Experimentally, a total of five pressure-volume-temperature (PVT) experiments including three sets of DME/CO2/heavy oil systems and two sets of DME/CO2/water/heavy oil systems have been carried out to measure saturation pressures, phase volumes, and swelling factors by using a versatile PVT setup. Theoretically, the modified Peng-Robinson equation of state (PR EOS) incorporated with the Huron-Vidal mixing rule and the Péneloux volume-translation strategy is employed as the thermodynamic model to perform phase equilibrium calculations. It is observed that the experimentally measured saturation pressures of DME/CO2/water/heavy oil mixtures are higher than those of DME/CO2/heavy oil mixtures at the same temperature and same molar ratio of solvents and heavy oil, owing to the fact that more water molecules can be evaporated into vapour phase. The binary interaction parameters (BIPs) between DME/heavy oil and CO2/DME pair, which are obtained by matching the measured saturation pressures of DME/CO2/heavy oil mixtures, work well for DME/CO2/heavy oil mixtures in the presence and absence of water. In addition, a swelling effect of heavy oil can be enhanced by adding the DME and CO2 mixtures compared to only DME or CO2. The new model developed in this work is capable of accurately reproducing the experimentally measured multiphase boundaries, swelling factors, phase volumes with a root-mean-squared relative error (RMSRE) of 4.68%, 0.71%, and 9.35%, respectively, indicating that it can provide fundamental data for simulating, designing, and optimizing the hybrid solvent-thermal recovery processes for heavy oil reservoirs.
Application of Machine Learning Methods to Well Completion Optimization: Problems with Groups of Interactive Inputs
Authors: Zhou Peng , Lu Ligang , Sang Huiyan , Dindoruk Birol
Published: September 2021

In unconventional reservoirs, optimal completion controls are essential to improving well productivity and reducing costs. In this article, we propose a statistical model to investigate associations between shale oil production and completion parameters (e.g., completion lateral length, total proppant, number of hydraulic fracturing stages), while accounting for the influence of spatially heterogeneous geological conditions on hydrocarbon production. We develop a non-parametric regression method that combines a generalized additive model with a fused LASSO regularization for geological homogeneity pursuit. We present an alternating augmented Lagrangian method for model parameter estimations. The novelty and advantages of our method over the published ones are a) it can control or remove the heterogeneous non-completion effects; 2) it can account for and analyze the interactions among the completion parameters. We apply our method to the analysis of a real case from a Permian Basin US onshore field and show how our model can account for the interaction between the completion parameters. Our results provide key findings on how completion parameters affect oil production in that can lead to optimal well completion designs.
Piloting the 1st Well-Test-Logging in the Middle East, Paving the Way to Low-Cost Dynamic Reservoir Characterization and Well Value Optimization
Authors: Nguyen Raymond , Jacques Antoine , Jaffrezic Vincent , Bigno Yann , Serry Amr Mohamed , Zakaria Hasan , Khan Owais Ameer , Jadallah Omar , Brouard Benoit
Published: September 2021

The development of carbonate reservoirs of a giant field, Offshore Abu Dhabi, requires long horizontal wells to maximize productivity, but at the risk of unwanted gas and water channeling through its inherent heterogeneities. Conformance can be enhanced with dedicated segmented completions (blank sections, Inflow Control Device, Autonomous Inflow Control Device, etc.) or selective acid stimulation (diverter, Limited Entry Liner), which are increasingly implemented to extend well life, and eventually well value.

If these technologies have matured, success depends heavily on the quality of the formation knowledge prior to completion. As of today, conventional logs provide the basic ground, but they lack dynamic information, whereas production logging results are obtained too late, when the well is already completed.

Initially introduced for the optimization of unconventional well completions (see Jacques et al, URTEC 2019), the Well Testing Logging (WTLog) offers the advantage to record a log of mobility, at the end of drilling the openhole, enabling a favorable timing to influence adapted completion and stimulation design. Contrasted viscosity brines are sequentially circulated through the drill pipes at a constant rate and back-produced from the casing at constant pressure. The fluids interface travels in the drain from the TD to the casing shoe, and the measurement of the differential formation seepage is interpreted into an injectivity profile. Combined with rate fall-off phase analysis, permeability and skin logs are derived. Lasting a few hours and realized with conventional rig equipment (such as cement pumps, coriolis flowmeters, Managed Pressure Drilling system), it is a nonintrusive, safe, and ultimately low-cost operation. Forward, it can replace costly logging, when aimed at characterizing heterogeneities.

Within a year, the two first WTLog pilots of the Middle East were successfully designed and carried out. They targeted two appraisal wells in distinct undeveloped reservoirs (Cretaceous and Upper Jurassic formations) which benefited from rich acquisition programs (Image log, Production log) to benchmark and qualify this technology.

After an explanation of the technology principles, this paper describes the design, operations, and results of these pilots. It then focuses on the petrophysical consolidation of the matrix/fracture characterization. It concludes by sharing the learnings and offers insight to what extent it is a promising technology to be applied in Middle East carbonate reservoir developments.
Digital Intelligent Artificial Lift DIAL Gas Lift Production Optimization Deployments Across Assets
Authors: Alshmakhy Ahmed , Bigno Yann , Saqib Talha , Soomro Moazim , Faustinelli Juan , Faux Stephen , BenAmara Abdel
Published: September 2021

Abu Dhabi National Oil Company (ADNOC) is expanding the use of DIAL (Digital Intelligent Artificial Lift) technology, across its assets, through a range of different oil production applications. These include gas lifted single and dual completions, Extended Reach Drilling (ERD) wells and In-Situ gas lift.

DIAL is a first-of-kind technology that enhances the efficiency of gas lift through downhole data, surface control and digital operations. This data driven approach enables production automation and minimizes well intervention requirements. This paper will present four different applications for the technology. These applications were selected by ADNOC assets, as they were deemed to bring the most value for DIAL implementation. The paper will describe technical details for each application, including gas lift designs, completion specificities, installation procedures and benefits observed or anticipated.

A summary of the value add for each of the four applications are listed below.

Gas lifted single completion is the most common application for the DIAL system. The benefits of the application have been described in previous papers and range from intervention savings to production optimization. This paper will highlight the additional benefit of automation, making full use of the system digital features. Gas lifted dual string completion, where the technology enables efficient lift of both strings, improving well production in the range of 40 to 100%. API (American Petroleum Institute) does not recommend pressure operated gas lift in dual wells. DIAL offers stability, simultaneous lifting of both strings through surface control and downhole data. ERD gas lifted well required flexibility for its gas lift operations. DIAL enables real time changes of injection depths based on reservoir response, and units can be installed deeper into the deviated section of the well without any deviation limits. In-Situ gas lift is a specific application where a gas zone is used to lift production from the oil zone in the same well. DIAL enables measurement of the gas injection rate at the point of injection, and adjustment of the flow area to optimize production. This is a world's first use of the technology for this type of application.

A range of applications are described in this paper with many technical details, recommendations and lessons learnt to enable replication within the industry. Some of these applications are world first.
History, Evolution, and Future of Casing Design Theory and Practice
Authors: Howard John A. , Trevisan Ruggero , McSpadden Albert , Glover Simon
Published: September 2021

Casing design and the associated load assumptions have evolved considerably over the last 30 years. The objective of this paper is to trace the history, evolution and future of casing design by means of the type of load cases and the assumptions made for them as it evolved from the early 1960's to the modern load case requirements for wells drilled in the 2020's. The vast majority of tubular failures in oil & gas wells are not attributable to computational errors in calculating design loads, but rather are due to a shortfall in considering the appropriate load scenarios. One common shortfall includes making incorrect or oversimplified assumptions for the initial and final temperature and pressure conditions. There is no industry standard for casing or tubing design loads, but there is an industry accepted standard process for the calculation of the stress on tubulars once the load cases are determined. Each operating company may use a different set of load assumptions depending on the well type and risk assessment.

This work also keeps in view the major computational tools used during each step change of the casing design evolution: slide rule/nomographs, HP 41C calculators, PC DOS and Windows programs, and the latest Cloud-Native paradigm with REST API's within a microservices architecture. A REST API (also known as RESTful API) is an Application Programming Interface (API) that conforms to the constraints of Representational State Transfer (REST) architectural style commonly used in current Cloud computing technology. The scope will also include ongoing research and development to address shortcomings of previous load case assumptions and calculations for extended reach and HPHT wells, closely spaced wells, and geothermal wells.

Modern wells and modern casing design load cases are in a constant state of evolution and casing failures will occur unless engineers and their tools also evolve.
Impact of Reservoir Fluid and Injection Gas on Shales Huff-N-Puff Performance in the Presence of Diffusion, Sorption, and Hysteresis
Authors: Enab Khaled , Emami-Meybodi Hamid
Published: September 2021

We assess the huff-n-puff performance in ultratight reservoirs (shales) by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, black oil) and different injection gases (CO2, C2H6, C3H8) by considering relative permeability hysteresis, diffusion, and sorption. A dual-porosity naturally fractured numerical compositional model is used that considers molecular diffusion and sorption to represent the flow mechanisms during the injection process. Killough's method, Langmuir's adsorption model, and Sigmund correlation are utilized to incorporate hysteresis, sorption, and diffusion, respectively. To investigate the impact of the fluid type, we consider three fluid types from Eagle Ford shale representing retrograde condensate, volatile oil, and black oil. We conduct a comprehensive evaluation of the impact of diffusion, sorption, and hysteresis on the production performance and retention of each fluid and injection gas. Eagle Ford formation is selected because it is the most actively developed shale, and it contains a wide span of PVT windows from dry gas to black oil.

The simulation results show that the huff-n-puff process improves the oil recovery by 4-6% when 10% PV of gas is injected. The huff-n-puff efficiency increases with reducing gas-oil-ratio (GOR) as oil recovery from low (GOR) reservoirs is doubled, while recovery from retrograde condensate increased by 20%. C2H6 provides the highest recovery for the black and volatile oil, and CO2 provides the highest recovery for retrograde condensate fluid type. Diffusion and sorption are essential mechanisms to be considered when modeling gas injection to any fluid type in shales. However, the relative permeability hysteresis effect is not significant. Neglecting diffusion during the huff-n-puff process underestimates the oil recovery and retention capacity. The diffusion effect on the oil density reduction is observed more during the soaking period. The diffusion impact increases with higher GOR reservoirs, while the sorption impact decreases with higher GOR. The retention capacity of the injected gas decreases with higher GOR. The diffusion impact on the retention capacity increases with higher GOR. Hence sorption and diffusion must be considered when modeling the huff-n-puff process in ultratight reservoirs.