bluuebunny/crossref_metadata_2025 huggingface dataset:
Geomechanical Implications of Reservoir Depletion vis-à-vis Post-Blowout Well Capping: A Gulf of Mexico Case Study
Authors: Michael Andreas
Published: September 2021

Reservoir depletion can impose major implications on wellbore integrity following blowouts. A loss-of-well-control event can lead to prolonged post-blowout discharge from the wellbore causing considerable reservoir depletion in a well's drainage area. Fractures initiated and propagated during well capping procedures following an offshore blowout can lead to reservoir hydrocarbons broaching the seafloor. In this paper, reservoir depletion is examined for a case study on actual deepwater Gulf of Mexico (GoM) parameters, evaluating analytically its impacts on in-situ reservoir conditions, hence assessing the likelihood of longitudinal or transverse fracture initiation during post-blowout well capping.

The reservoir rock is modeled as a porous-permeable medium, considering fluid infiltration from the pressurized wellbore. A novel analytical workflow is presented, which encompasses the major effects of reservoir depletion on the (i) in-situ stress state, (ii) range of in-situ stress states stable against shear fault slippage, and (iii) limits of tensile fracture initiation. The geomechanical implications of each individual effect on post-blowout well capping is discussed with the individual results illustrated and analyzed altogether on dimensionless plots. These plots are useful for engineers when making contingency plans for dealing with loss-of-well-control situations. The workflow is demonstrated on a case study on parameters taken from the M56 reservoir, where the April 20, 2010 blowout took place at the MC 252-1 "Macondo" well.

A smaller post-blowout discharge flowrate is shown to increase the shut-in wellbore pressure build-up at any given time-point following well capping, whereas an increased post-blowout discharge period leads to a lower shut-in wellbore pressure build-up, hence reducing the likelihood of a fracture initiation scenario and vice versa. Assuming a robust wellbore architecture, the most likely location of fracture initiation is the top of the M56 reservoir within the openhole section of the Macondo well. The critical discharge flowrate, an established indicator for fracture initiation during well capping using information from the post-blowout discharge stage is employed, pointing that fracture initiation is highly-unlikely for the assessed parameters. Nevertheless, fracture initation during post-blowout well capping remains a real possibility in the overpressurized, stacked sequences of the GoM. Finally, the model is extended to an "incremental"/multi-step capping stack shut-in imposed over a longer time-period (e.g. 1 day than abruptly over a single-step) to suppress the wellbore pressure build-up, if necessary to avoid fracture initiation.
Application of Air Cooled Heat Exchangers for Condensation of Natural Gas Liquids from Associated Petroleum Gas
Authors: Prokopev Mikhail , Vorobev Ilya , Rakhmangulov Yulay , Litvak Egor
Published: September 2021

The paper describes a method for increasing a yield of stock-tank oil by reducing liquid carryover with associated petroleum gas at crude processing facilities (CPF) of one oil field in Iraq by cooling the feed stream in air cooled heat exchangers. An integrated model of the field has been built consisting of: models of well tubings, models of wellhead chokes, an integrated model of oil gathering network, a model of air cooled heat exchangers, a model of material and heat balance of CPF. The air cooler performance in oil treatment has been asessed in accordance with ambient temperature profile. The main advantages and disadvantages of using the proposed scheme are shown in the article.

Considered in the article the air cooler has been originally designed and manufactured for use in another field. Therefore, one of the tasks was to validate the applicability of that air cooler unit in the oil treatment process for a field with facilities in-place. The novelty of the study lies in the non-standard use of an air cooled heat exchangers in the oil treatment.

The results of simulation of using air cooling units in oil treatment and the actual operation of air coolers showed increased output of crude oil at the CPF at low capital and operating costs.
Simultaneous Fracturing Operations: Successful Implementation and Lessons Learned
Authors: Algadi Otman , Mclaughlin Nathan , Wilpitz Louis , Farrell Tony , Gamadi Talal
Published: September 2021

Today’s multistage hydraulic fracturing operations often demand complex treatments that incorporate high injection rates along with high volumes of proppant and fluid. It is challenging, however, to execute these treatments in a time- and cost-efficient manner while still maintaining optimal treatment quality. This paper discusses the applicability and limitations of the simultaneous-fracturing (simul-frac) completion technique – a solution that offers considerable advantages to help operators meet increasing industry demands to "do more with less". Simul-frac involves hydraulically fracturing two or more adjacent horizontal wells simultaneously. This technique provides an effective solution to the challenges mentioned above.

A controlled field study was conducted on three four-well pads, on the same Permian Basin lease, with identical/matching well geometry, landing zones, lateral lengths, and treatment designs. Two pads were completed using a traditional zipper-frac operation, while one pad was completed using the simul-frac technique. Designed to analyze operational efficiency, overall completion cost and impact on well productivity, this study provides an unprecedented, precise comparison between simul-frac and traditional zipper completions.

The controlled field study provided valuable insight into how the simul-frac technique can affect operational efficiencies. Unlike zipper-frac operations, all four wells on the pad were being either fractured or perforated at the same time, so there was never a time when one or more wells sat idle. By fracturing two stages simultaneously, the crew was able to complete more lateral footage, compared to fracturing a single stage with zipper frac. This, in turn, shortened overall operational time to complete the pad by five days. These saved days reduced overall completion costs and allowed for earlier return on investment by putting the wells on production sooner.

Like traditional zipper-frac operations, simul-frac operations are performed by a single frac crew, requiring minimal equipment modification or alteration to treatment execution procedures. However, the simul-frac technique is a complex operation that presents unique risks and challenges, including: simultaneous injection of fracturing fluid into two wells at a higher total injection rate, higher proppant and daily chemical-consumption rate, two cranes and two wireline trucks on the same pad, and pairing of wells with different landing zones. These risks are manageable, and service providers can achieve the desired results by providing exceptional communication and expertise at the wellsite.

Simul-frac operations enable operators to execute multistage well stimulation faster and more efficiently. It introduces greater operational efficiencies by enabling the crew to operate at peak performance and by eliminating well idle time. These advantages translate to lower overall completion costs and reduced time to first production.
Corrosion Inhibition Enhancement for Surface O&G Operations Using Nanofluids
Authors: Mazo Camilo , Lopez Daniel , Forero Angela Marcela , Maya Andres , Lesmes Miguel , Cortés Farid Bernardo , Franco Camilo Andres
Published: September 2021

The main objective of this study is to develop and evaluate a nanotechnology-based material in combination with a commercial corrosion inhibitor (CI) as an alternative to reduce the corrosion rate in oil and gas facilities. The corrosion rate (CR) of surface facilities coupons was estimated using weight loss analysis as the response variable in the following study, showing that in absence of CI treatments, carbon steel (CS) coupon displays corrosion rates over 2.1 mm·y−1. Four commercial CI were evaluated at concentrations ranging between 35-50 mg·L−1 to select the most suitable treatment at surface facilities conditions, showing CR reductions of around 12.2 and 22.5% in both dosages for the best CI treatment. SiO2 and Carbon Quantum Dots (CQDs) nanomaterials were added to the selected CI at nanoparticle dosages from 50 to 500 mg·L−1 to improve the behavior of the selected treatment in presence of production brine. The effectiveness of the proposed nanomaterials is strongly dependent on the nanoparticle concentration, and hence, its dispersion degree onto the metallic surface, whereas low dosages in SiO2 lead to an increase in the CR, however, low dosages in CQD lead to a reduction of the CR. The proposed NanoIC was evaluated using 1M HCl solutions to study the role of the nanoparticles in strong acid media. The corrosion rates for CS outcrops in the presence of production brine with 1M HCl was 8.6 mm·y−1, which suggests an important role of mineral acids in the corrosion phenomena. In the presence of CI at a dosage of 35 mg·L−1, the corrosion rate was reduced by 10.7%. The CR of CS surfaces treated with brine and strong acid solutions in presence of NanoCI containing CQD nanomaterials at 50 mg·L−1 shows reductions of 28.6 and 74.2%, respectively. It can be concluded, the nanoparticles act as a corrosion inhibitor agent, reducing the interaction between the acid molecules and the steel surface by the formation of a thin film. This work opens the landscape into the incorporation of carbon-based nanomaterials in surface oil and gas operations for the reduction of the corrosion rate in the facilities during the production stage in the wells by the synergistic behavior between commercial corrosion inhibitor and nanoparticles.
Liners with Bulk Metallic Glass/High Entropy Alloy, Degradable in Formation Fluids for a Skin Free, Clear, Perforating Tunnel, Enabling Enhanced Reservoir Connectivity
Authors: Chen Roy Ting , Bennaceur Kamel , Markel Daniel , Harp Leonard , Harrison Casey , Shelton James , Hall Aaron , Kashyap Rashi , Ramesh Kris , Wilkinson Christian , Roy Indranil
Published: September 2021

A shaped charge for wellbore perforation includes a solid metal or powder liner pressed onto a case, sandwiching high explosives which may have varying thermal stability, dictated by the expected time of exposure and bottom hole temperature (BHT). It is common knowledge that post detonation, the liner-jet punctures the gun body and casing, continuing forward to perforate the formation until its eventual collapse. The jet debris is deposited on the crushed zone forming an impermeable skin and a slug at the end of the perforation-tunnel. This reduces fracture conductivity, and thus, production. Here we present a game changing innovation, the development of a shaped charge with a novel responsive liner. The jet created from our novel degradable liner, post detonation punctures the casing and progress to penetrate the formation until an eventual collapse. However, this system is designed so that, during detonation, a water disintegrable reaction product, bulk metallic glasses (BMG) and/or high entropy alloys (HEA), are formed. These degradable BMG/HEA or complexions decorate the grain boundaries and domain interfaces of the impermeable skin lining the crushed zone of the perforation tunnel as amorphous intergranular films (AIFs) and plug at end of the pathway. Interacting with flowback fluids the BMG/HEA promotes grain dropping, disintegrating the liner and carrot leaving behind a clean perforation tunnel, improving fracture conductivity thus enhanced productivity. In addition, a clear perf tunnel has zero skin value. As such, compared to a coated tunnel with gun and charge debris, it needs little or no acid to clean-up. This results in a demarked reduction of formation breakdown pressures with improved economics for the client. Last but not least this leads to cost reduction of authorized field expenditure (AFE) to support optimized performance of completion design allowing for increased production. CLEAR shaped charges have been qualified to customer specifications in field conditions and are ready to be commercialized. An extension of this technology is being applied to design charges for "Big-Hole" perforations, for the Plug and Abandonment (P&A) market where an effective cement squeeze, anchoring a plug effectively seals the wellbore, preventing the leakage of residual hydrocarbon and associated contamination and emissions.
A Back Allocation Methodology to Estimate the Real-Time Flow and Assist Production Monitoring
Authors: Chaves Gabriela , Monteiro Danielle , Martins Ferreira Virgilio José
Published: September 2021

Commingle production nodes are standard practice in the industry to combine multiple segments into one. This practice is adopted at the subsurface or surface to reduce costs, elements (e.g. pipes), and space. However, it leads to one problem: determine the rates of the single elements. This problem is recurrently solved in the platform scenario using the back allocation approach, where the total platform flowrate is used to obtain the individual wells’ flowrates. The wells’ flowrates are crucial to monitor, manage and make operational decisions in order to optimize field production. This work combined outflow (well and flowline) simulation, reservoir inflow, algorithms, and an optimization problem to calculate the wells’ flowrates and give a status about the current well state. Wells stated as unsuited indicates either the input data, the well model, or the well is behaving not as expected. The well status is valuable operational information that can be interpreted, for instance, to indicate the need for a new well testing, or as reliability rate for simulations run. The well flowrates are calculated considering three scenarios the probable, minimum and maximum. Real-time data is used as input data and production well test is used to tune and update well model and parameters routinely. The methodology was applied using a representative offshore oil field with 14 producing wells for two-years production time. The back allocation methodology showed robustness in all cases, labeling the wells properly, calculating the flowrates, and honoring the platform flowrate.
The Application of Data Validation and Reconciliation to Upstream Production Measurement Integration and Surveillance – Field Study
Authors: van der Bent Vincent , Amin Amin , Jadot Timothy
Published: September 2021

With the advent of increased measurements and instrumentation in oil and gas upstream production infrastructure; in the wellbore, in subsea and on surface processing facilities, data integration from all sources can be used more effectively in producing consistent and robust production profiles. The proposed data integration methodology aims at identifying the sources of measurement and process errors and removing them from the system. This ensures quasi error-free data when driving critical applications such as well rate determination from virtual and multiphase meters, and production allocation schemes, to name few. Confidence in the data is further enhanced by quantifying the uncertainty of each measured and unmeasured variable.

Advanced Data Validation and Reconciliation (DVR) methodology uses data redundancy to correct measurements. As more data is ingested in a modeling system the statistical aspect attached to each measurement becomes an important source of information to further improve its precision. DVR is an equation-based calculation process. It combines data redundancy and conservation laws to correct measurements and convert them into accurate and reliable information. The methodology is used in upstream oil & gas, refineries and gas plants, petrochemical plants as well as power plants including nuclear. DVR detects faulty sensors and identifies degradation of equipment performance. As such, it provides more robust inputs to operations, simulation, and automation processes.

The DVR methodology is presented using field data from a producing offshore field. The discussion details the design and implementation of a DVR system to integrate all available field data from the wellbore and surface facilities. The integrated data in this end-to-end evaluation includes reservoir productivity parameters, downhole and wellhead measurements, tuned vertical lift models, artificial lift devices, fluid sample analysis and thermodynamic models, and top facility process measurements. The automated DVR iterative runs solve all conservation equations simultaneously when determining the production flowrates "true values" and their uncertainties. The DVR field application is successfully used in real-time to ensure data consistency across a number of production tasks including the continual surveillance of the critical components of the production facility, the evaluation and validation of well tests using multiphase flow metering, the virtual flow metering of each well, the modeling of fluid phase behavior in the well and in the multistage separation facility, and performing the back allocation from sales meters to individual wells.
Empowering Technical and Soft Skills in Students and Young Professionals of the Oil&Gas Industry
Authors: Ardila Díaz David Enrique , Galvís William Genghini , Jaramillo Medina Sandra Juliana , Sanchéz Alejandro , Velásquez Sergio , Mantilla Cesar , Pastor Chacón Paola Andrea
Published: September 2021

To contribute to the construction of young professionals with an integral profile in which the competitive spirit is promoted through the resolution of a technological challenge applied to the Oil & Gas industry, under a scenario that demands a high degree of commitment and with the accompaniment of professionals with great experience in the industry.

In accordance with the data acquired and the program's target population, an appropriate methodology has been established for the development and strengthening of technical and soft skills. This methodology consists of four main phases: 1. Challenge construction 2. Best Teams selection 3. Challenge Resolution and 4. Results presentation. During the challenge resolution phase, participants have multiple technical and soft skills training sessions where experienced professionals share their knowledge and experiences related to the challenge theme in an environment of generational knowledge transfer.

During the last 4 years, around 120 participants from different cities of the country have managed to potentiate their soft skills and strengthen their knowledge in areas of the Oil & Gas industry such as unconventional, enhanced recovery, heavy oil, huff & puff, combustion had tests, wettability, waterflooding, among others and materialize it with the construction of an innovative technological tool. The best of each version was rewarded with their first work experience in the Oil & Gas industry where they were able to put into practice what they had learned during the program. Likewise, the continuous acquisition of valuable information about variables at the end of the program such as the knowledge areas of greatest interest for students and young professionals, the level of knowledge related to oil engineering and programming, the handling of a second language, and the skills acquired during the university training stage, has allowed strengthening the methodology of the"SPE en Sinergia" program, adjusting it to the current needs of the industry and placing the participants outside their comfort zone.

The development of the program and the results obtained are based on the identification of the strengths and weaknesses currently displayed by students in their final semesters and young professionals in careers related to petroleum engineering in Colombia and that in one way or another have become part of the reasons why their link to the professional world has become more difficult. This has enabled a way to identify opportunities for improvement and establish lines of action to promote the professional fast-track development of the new generations in a joint effort between industry and academia.
Design and Experimental Research of a Fiber-Optic Communication Module for Well Logging
Authors: Wang Yue , Li Bo , Sun Lei , Hao Fenghuan , Rourke Marvin
Published: September 2021

Fiber-optic transmission has been applied in oil and gas industry over the years. Compared with other methods applied in the industry, fiber-optic transmission has the advantages of low loss, long-distance, high-capacity and robust to the electromagnetic interference. The ability to provide reliable transmission systems in the harsh environments like high temperatures is the key driver for the continued use of fiber-optic communication for in-well applications.

We design a fiber-optic communication system under high temperatures for well logging applications. It consists of high-temperature laser diode, high-temperature photodetector with photoelectric detection circuit, drive control circuit, and field-programmable gate array (FPGA) as the communication chip. This system ensures that data can be transmitted at a rate of 15 Mbps at temperatures up to 155°C. The FPGA board makes the system to control data transmission flexibly and enable the serial communication between the photoelectric module and the host computer. Additionally, the number of fibers used in fiber-optic communication in logging will be reduced to only a single fiber for transmitting and receiving.

A series of experiments on the performance and effects of fiber-optic communication at different temperatures was carried out. Data transceiver tests and eye diagram tests are presented. The experimental results demonstrated that this fiber-optic communication system is capable of working steadily over a long period of time in harsh environments around 155°C to realize broadband and remote transmission of logging information.

This system provides a way that allows optical information to transmit in a high-temperature environment. It can be applied to well logging and fiber-optic sensing (e.g., real-time environmental parameters transmission, fiber-optic well monitoring) for developing real-time, high-data-rate, bidirectional fiber-optic communication in the future.
Experiments of Liquid Loading and Intermittent Production Using a Lab-Scale Reservoir-Tubing Setup
Authors: van 't Westende Jos , van Nimwegen Dries , Belfroid Stefan , Slot Harmen
Published: September 2021

Experiments were performed to investigate the physics behind intermittent production and liquid loading, using a setup containing a reservoir model coupled to a vertical production tubing. In the experiments both gas and liquid are injected into the reservoir, which is a container in which sand with two different permeabilities is placed. Quick closing valves are incorporated into the experimental setup in order to simulate well shut-ins and start-ups. The experimental results show that the addition of the reservoir to the experimental set-up shifts the minimum in the total pressure losses over the system to lower gas flow rates as the permeability of the reservoir decreases. When performing shut-ins where a significant liquid column is present in the tubing, as is the case in liquid loaded wells, performing a sufficiently long shut-in can lead to the deliquification of the system.
Automating the Log Interpretation Workflow Using Machine Learning
Authors: Sankaranarayanan Bhuvaneswari , Abubakar Aria , Allen David F. , Diaz Granados Ivan
Published: September 2021

Log interpretation is the task of analyzing and processing well logs to generate the subsurface properties around wells. A direct application of machine learning (ML) to this task is to train an ML model for predicting properties in target wells given well logs (data) and properties (labels) in a set of training wells in the same field and/or region.

Our ML model of choice for predicting the desired properties is the decision tree-based learning algorithm called random forests (RF). We also devise a mechanism to automatically tune the hyperparameters of this algorithm depending on the data in the training wells. This eliminates the tedious task of carefully tuning the hyperparameters for every new set of training wells and provides a one-click solution. In addition to predicting the properties, we compute the uncertainty in the predicted properties in the form of prediction intervals using the concept of quantile regression forests (QRF).

We test our workflow on two use cases. First, we consider a petrophysics use case on an unconventional land dataset to predict the petrophysical properties such as water saturation, total porosity, volume of clay, and total organic carbon from petrophysics logs. Then, we consider a geomechanics use case on a conventional offshore dataset to predict the lithology, pore pressure, and rock mechanical properties. We obtain a good prediction performance on both use cases. The uncertainty estimates also complement the ML model's prediction of the properties by explaining the various correlations that are found to be existing among them based on domain knowledge.

The entire workflow of automating the tuning of hyperparameters and training the ML model to predict the properties along with its estimate of uncertainty provide a complete solution to apply the ML workflow for automated log interpretation.
A Generalized Model for the Field Assessment of Drilling Fluid Viscoelasticity
Authors: Hongbo Chen , Temi Okesanya , Ergun Kuru , Garett Heath , Dylan Hadley
Published: September 2021

Recent studies highlight the significant role of drilling fluid elasticity in particle suspension and hole cleaning during drilling operations. Traditional methods to quantify fluid elasticity require the use of advanced rheometers not suitable for field application. The main objectives of the study were to develop a generalized model for determining viscoelasticity of a drilling fluid using standard field-testing equipment, investigate the factors influencing drilling fluid viscoelasticity in the field, and provide an understanding of the viscoelasticity concept.

Over 80 fluid formulations used in this study included field samples of oil-based drilling fluids as well as laboratory samples formulated with bentonite and other polymers such as partially-hydrolyzed polyacrylamide, synthesized xanthan gum, and polyacrylic acid. Detailed rheological characterizations of these fluids used a funnel viscometer and a rotational viscometer. Elastic properties of the drilling fluids (quantified in terms of the energy required to cause an irreversible deformation in the fluid's structure) were obtained from oscillatory tests conducted using a cone-and-plate type rheometer. Using an empirical approach, a non-iterative model for quantifying elasticity correlated test results from a funnel viscometer and a rotational viscometer.

The generalized model was able to predict the elasticity of drilling fluids with a mean absolute error of 5.75%. In addition, the model offers practical versatility by requiring only standard drilling fluid testing equipment to predict viscoelasticity. Experimental results showed that non-aqueous fluid (NAF) viscoelasticity is inversely proportional to the oil-water ratio and the presence of clay greatly debilitates the elasticity of the samples while enhancing their viscosity.

The work efforts present a model for estimating drilling fluid elasticity using standard drilling fluid field-testing equipment. Furthermore, a revised approach helps to describe the viscoelastic property of a fluid that involves quantifying the amount of energy required to irreversibly deform a unit volume of viscoelastic fluid. The methodology, combined with the explanation of the viscoelasticity concept, provides a practical tool for optimizing drilling operations based on the viscoelasticity of drilling fluids.
Single Trip Deployment of Multi-Stage Completion Liners Through the Used of Interventionless Flotation Collars
Authors: Tait William , Munawar Mohammed
Published: September 2021

Due to challenging market conditions, the drilling and completion industry has needed to put forth innovative deployment strategies in horizontal multi-stage completions. In difficult wellbores, the traditional method for deploying liners was to run drill pipe. The case studies discussed in this paper detail an alternative method to deploy liners in a single trip on the tieback string so the operator can reduce the overall costs of deployment. Previously, this was not practical because the tieback string weight could not overcome the wellbore friction in horizontal applications.

In each case, a flotation collar is required to ensure there is enough hook load for deployment of the liner system. The flotation collars used are an interventionless design, utilizing a tempered glass barrier that shatters at a pre-determined applied pressure. The glass debris can be easily circulated through the well without damaging downhole components. This is done commonly on cemented liner and cemented monobore installations, but more rarely with open hole multi-stage completions. For open hole multi-stage completions, the initial installation typically requires an activation tool at the bottom of the well to set the hydraulically activated equipment above.

Multiple validation tests were completed prior to installation by using an activation tool and flotation collar to ensure the debris could be safely circulated through the internals without closing the activation tool. These activation tools have relatively limited flow area and could cause an issue if the glass debris were to accumulate and shift it closed prematurely. Premature closing of the tool would leave expensive drilling fluids in contact with the reservoir, potentially harming production. For the test, the flotation collar was placed only two pup joints away from the activation tool, resulting in a worst-case scenario where a large amount of debris could potentially encounter the internals of the activation tool at one time. In a downhole environment the flotation collar is typically installed near the build or heel of the well, depending on wellbore geometry. The testing was successfully completed, and the activation tool showed no signs of loading. This resulted in a full-scale trial in the field where a 52 stage, open hole (OH) multi-stage fracturing (MSF) liner was deployed using this technology.

Through close collaboration with the operator, an acceptable procedure was established to safely circulate the glass debris and further limit the risk of prematurely closing the activation tool. This paper discusses the OH and cemented MSF deployment challenges, detailed lab testing, and field qualification trials for the single trip deployed system. It also highlights operational procedures and best practices when deploying the system in this fashion. A method to calibrate a torque and drag model will also be explored as part of this discussion.
Rate Transient Analysis of Heterogeneous Unconventional Gas Reservoir Using a Fractional Decline Model
Authors: Luong Loc
Published: September 2021

In this study, an extended version of the fractional decline model is analytically developed for gas flow in fracture reservoir using the anomalous diffusion equation incorporated with the fractional calculus and equation of state. The model can represent the heterogeneity of complex fracture networks and can further be used to interpret reservoir properties by performing type-curve matching of flow rate and cumulative production from multi-fractured horizontal wells in unconventional reservoirs.

To address the limitations of conventional planar fracture idealization, the hydraulic fractures in this present study are integrated with the fracture network, and the fractional diffusivity is solved for a horizontal wellbore. Upon establishing and solving the governing equation in the Laplace domain, the solutions are converted back to the real-time and space domain by performing numerical Laplace inversion. A set of distinctive type curves is generated on the basis of an infinite conductivity horizontal well model, considering early and middle times, in order to capture the heterogeneity of the fractal network in the reservoir model. Application of this new model is demonstrated through type-curve matching of two synthetic cases of simulation data obtained from commercial software; the cases cover orthogonal evenly and unevenly distributed networks. Results from these examples show an acceptable match between the fractional decline model and synthetic data and, hence, showcase the applicability of this model to capture the transient flow in heterogeneous fractured reservoirs.
Improving Well and Reservoir Management Practice Through New Flow Control Philosophy that Prolongs the Life of Production Wells Affected by Water Breakthrough in A Giant Carbonate Oil Field, Abu Dhabi, United Arab Emirates
Authors: Ortiz Requena Jhon Robert , Martinez Santiago Maryvi , Alshehhi Fatmah Mohamed , Daudpota Fareed Ahmad , Fawzy Ahmed Mohamed
Published: September 2021

X Field located in the United Arab Emirates has been developed since 1970's by waterflooding as secondary recovery strategy. As water front advances into oil bank, the well operation practice commonly adopted in many fields for oil wells cutting water has consisted in reducing choke aperture in an attempt to control the water cut trend. However, in wells producing moderate to high water cut, this practice has proven to generate excess water settling in the bottom of the wellbore leading to premature inactivation of the wells.

The reservoir Z in the north of X Field, is a black oil block operated by peripheral and pattern waterflooding. The production wells have been operating by natural lifting since first oil and will continue in natural flow until the Artificial Lift projects are commissioned within a few years. Meanwhile, the field production plateau has been increased arising challenges of production sustainability due to higher risk of acceleration of water breakthrough and consequently higher number of wells becoming inactive earlier. This led to re-assess the Well and Reservoir management strategy to define improved practices oriented to maximize the natural life cycle of wet wells and ensure the compliance of the field production quota. As a result, a new well management approach was devised and adopted to identify and optimize at the earliest stage, wells potentially affected by water loading mismanage. Conceptually, this new practice consisted in comprehensively analyzing well operating conditions, which ultimately generated a flow operating window that improved the multiphase flow performance in wellbores, minimized water slippage avoiding it to settle down and its associated problems, whilst respecting the compliance of technical guidelines for optimum reservoir management.

Based on observations and data gathered from portable testing jobs, saturation logs, PLT and production monitoring; a methodology referred in this work as Critical Flow Analysis, has been successfully implemented in several naturally flowing wells with water cuts ranging from 15 – 40 % in Reservoir Z in X Field, which resulted in prolonged natural life, extra oil recovered, and avoided the negative impact of inactive string count on the Field Management KPI.

The Critical Flow analysis has been a comprehensive well management evaluation and operation philosophy in Reservoir Z which helped to manage more efficiently and in cost-saving fashion the performance of oil wells located in high risk areas, in addition to contribute with stablishing best practices for well and reservoir management that could be extended to analog fields in the area.
A Real-Time Probabilistic Slide Drilling Dysfunction Advisory to Assist Remote Directional Drilling Operations
Authors: Ramos Dawson , Ashok Pradeepkumar , Yi Michael , D’ Angelo John , Rostagno Ian , Bohlander Spencer , Thetford Taylor , Moisan James , Behounek Michael , Noworyta Mickey , Beasley Jason , Wilson Joshua
Published: September 2021

Current slide drilling practices rely heavily on the intuition of the directional drillers to identify and correct drilling dysfunctions. Monitoring numerous dysfunctions simultaneously requires more complex analysis than can be done manually in real-time. There is also currently a big shift towards remote directional drilling. And as such, there is the need for a tool that can, in real-time, diagnose slide drilling dysfunctions accurately and provide advisory to both the remote directional drillers and rig crew.

This paper proposes a method for a real-time slide drilling advisory system consisting of a probabilistic model which computes the likelihood that various slide drilling dysfunctions are occurring and an algorithm that determines what corrective action, if any, should be taken as a result. The dysfunction types monitored include buckling, high friction, poor toolface control, stick slip, and bit bounce. The model employs a Bayesian network which uses evidence derived from transient drilling data trends to infer the probability that any of the five considered dysfunctions are taking place. Data trends known to correlate with each dysfunction type are considered simultaneously to ensure that all dysfunction types are monitored continuously. As dysfunction probabilities are calculated, the algorithm cross references them with current drilling parameters and contextual data to determine necessary corrective actions. Corrective actions are output in the form of simple drilling parameter changes shown on a customizable graphical display.

The dysfunction beliefs calculated were validated using historical data gathered from North America land drilling operations. For high friction and poor toolface control, known instances of dysfunction were identified using information in drilling logs and expert opinion and used for validation. The validation process resulted in a further refinement of the model. The proposed model along with graphical advisory displays were deployed on rigs in several North American land well drilling operations, as well as in the remote directional drilling center.

While there is a lot of prior work that enables identification of rotary drilling dysfunctions in real-time, this is the first method that diagnoses slide drilling dysfunctions in real-time. The approach combines physics based models with a Bayesian network to improve accuracy and robustness in dysfunction detection. Additionally, it considers both real-time drilling data as well as drilling data from the past when diagnosing dysfunctions and facilitates remote directional drilling.
Automating Well Log Correlation Workflow Using Soft Attention Convolutional Neural Networks
Authors: Abubakar Aria , Kulkarni Mandar , Kaul Anisha
Published: September 2021

In the process of deriving the reservoir petrophysical properties of a basin, identifying the pay capability of wells by interpreting various geological formations is key. Currently, this process is facilitated and preceded by well log correlation, which involves petrophysicists and geologists examining multiple raw log measurements for the well in question, indicating geological markers of formation changes and correlating them with those of neighboring wells. As it may seem, this activity of picking markers of a well is performed manually and the process of ‘examining’ may be highly subjective, thus, prone to inconsistencies. In our work, we propose to automate the well correlation workflow by using a Soft- Attention Convolutional Neural Network to predict well markers. The machine learning algorithm is supervised by examples of manual marker picks and their corresponding occurrence in logs such as gamma-ray, resistivity and density. Our experiments have shown that, specifically, the attention mechanism allows the Convolutional Neural Network to look at relevant features or patterns in the log measurements that suggest a change in formation, making the machine learning model highly precise.
Exploration Drilling Management System Based on Digital Twins Technology
Authors: Kalinin Oleg , Elfimov Maksim , Baybolov Timur
Published: September 2021

Digital transformation of oil and gas companies requires consistent improvement of work performance management. Oil and gas companies strive to improve work efficiency and consistently develop and implement digital products. The realization of such complicated solutions requires deep diving into current business processes and transformation of them. This paper deals with implementation of digital management system for exploration and production wells.

Digital management system for exploration and production wells is based on ideology of digital twin and act as a single window and single source of data for all exploration and production wells. Digital management system covers whole construction process started from planning stage to execution and results assessment and orchestrates the exchange of data between process phases and people involved in it. Transparency provided by the digital twin improves efficiency and accelerates well construction process.

Cognitive assistants based on AI and ML techniques are implemented at every stage: while planning, the assistants search analogue wells, analyze its design and complications while drilling and provide recommendations for the most optimal well design, offers the optimum drilling mud density and recommends the most suitable set of logs to cover geological section uncertainty. At the execution stage, a number of ML assistants are used to increase efficiency and reduce risks while drilling: automatic method for anomaly detection while drilling to prevent complications while drilling, machine learning based model for automatic torque and drag control to control borehole condition to predict any signs of differential stuck, key sitting and pack-off, data-driven model for drilling bit position and direction determination to predict BHA position while drilling including a blind zone, data-driven model for the identification of the rock type at a drilling bit for correct geosteering application.
Downhole Oil Water Separation to Handle Produced Water Study Case Onshore & Offshore Fields Abu Dhabi
Authors: Ladmia Abdelhak , Alblooshi Younes , Alobedli Abdullah , Zivanov Dragoljub , Kuliyev Myrat , Deblais Eric , Al Beshr Manal , Al Shmakhy Ahmed , Abdullsalam Fouad , El Bekshy Amer , Almarzooqi Maitha , Maulana Sahid , Bin Ali Amirul , Douik Hela , Al Jaberi Bashaer , Abdelkerim Ali Issa
Published: September 2021

The expected profiles of the water produced from the mature ADNOC fields in the coming years imply a 5-fold increase and the OPEX of the produced / injected water will increase considerably. This requires in-situ water separation and reinjection. The objective is to reduce the cost of handling produced water and to extend the well natural flow performance resulting in increased and accelerated production.

The current practice of handling produced water is inexpensive in the short term, but it can affect the operating cost and the recovery in the long term as the expected water cut for the next 10-15 years is high.

A new water management tool called downhole separation technology was developed. It separates Oil & Gas from produced water inside the wellbore and injects the produced water into the disposal wells. The Downhole Oil Water Separation Technology is one of the key development strategies that will reduce the handling Produced water, improve the recovery, and minimize field development cost by eliminating surface water treatment and disposal well.

The main benefits for DHOWS are to accelerate Oil Offtake, reduce Production Cost, Lower Water Production and Improve facility Utilization. DHOWS require specific criteria to meet the objectives of the well. Multi-disciplined inputs are needed to properly install effective DHOWS, but robust design often brings strong performance.

This paper describes the fundamental criteria and workflow for selecting the most suitable DHOWS design for new and sidetracked wells to deliver ADNOC production mandates cost effectively while meeting completion requirements and adhering to reservoir management guidelines.
A New Generation of Steerable Drilling Motor is Born - Understand the Unique Geometry, Drilling Benefits and Performance Gains
Authors: Jones Steve , Sugiura Junichi
Published: September 2021

Steerable drilling motors still dominate US shale drilling applications. Shale well construction is commonly planned with monobore vertical, high dogleg-severity (DLS) curve and lateral sections. Limitations arise in each portion of the wellbore because one single bottomhole assembly (BHA) does not provide optimal results; hence, trips are required to optimize the BHA.

The main disadvantage with existing steerable drilling motors is the requirement for high bend-angle settings to drill the high DLS curve portion of the wellbore. The geometry of a high bend-angle motor is only optimal for slide drilling the curve, it is not optimal for drilling the vertical and lateral portions of the wellbore. While drilling the vertical and lateral portions of the well, surface RPM (revolutions per minute) must be limited to reduce the cyclic bending fatigue on the large external bend. Not to mention poor wellbore quality while rotary drilling with a large external bend.

To overcome this issue, a new geometry design was required. The new-generation motor uses a tilted internal drive mandrel aligned with a small external bend. This combination delivers the best of both worlds, providing high DLS capability while slide drilling and high surface-RPM capability while rotary drilling (because of the small external bend).

Compact embedded drilling dynamics data recorders were used to validate the dynamic improvement of the new steerable-drilling-motor geometry versus older-style geometry with large external bend. The embedded sensors recorded at-point dynamics of shock and torsional response providing detailed comparative data sets during the development phase.

The new-generation steerable-drilling-motor technology utilizes point-the-bit rotary-steerable-system (RSS) methods (for example, a tilted mandrel) with conventional steerable-motor methods (for example, an external bend). The combination of the internal tilt and external bend (aligned together) provides a completely new geometry for a steerable motor. This new geometry is beneficial for high DLS sliding capability, high surface-RPM rotary drilling and improved borehole quality (slide/rotate transition and rotary mode).

This new steerable drilling motor with enhanced geometry was utilized to prove delivery of vertical/curve/lateral in one run, consistent DLS through the curve and improved tracking in the lateral. The results from development testing (comparing to older-geometry motors) will be described in this paper.