bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Pilot Test of Micro-Dispersed Gel Foam in Fractured-Vuggy Carbonate Reservoirs
Authors: Wen Yuchen , Hou Jirui , Qu Ming , Wu Weipeng , Liang Tuo , Zhang Wei , Wu Wenming
Published: September 2021

This paper summarizes the change rule of production performance and the EOR efficiency from the micro-dispersed gel foam injection in the fractured-vuggy carbonate reservoir of Tahe Oilfield. The TK722CH2 well group injected gas from August 2014 to September 2018. During the gas injection stage, the effect of periodic gas injection decreased obviously, the effective direction of gas injection was single and the risk of gas channeling increased greatly. The field pilot test f micro-dispersed gel foam was carried out on September 20, 2018. The fluid is injected into well group in three slugs: micro-dispersed gel foam, normal foam and nitrogen gas. As a part of the foam pilot test monitoring, a gas tracer study was performed before and after the injection of gel foam in the reservoir. After the pilot test was carried out in the TK722CH2 well group, the subsequent injection gas swept new fractures and vugs, and a new dynamic connectivity has been established. The connectivity of well group changed from 1 injection well connects with 1 production well to 1 injection well connects with 4 production wells. Through the field pilot test of micro-dispersed gel foam, this paper verifies the effect of improve gas flooding and increase sweep volume of micro-dispersed gel foam. By analyzing the results of the field pilot test, the relevant technical mechanism of micro-dispersed gel foam in fractured-vuggy reservoir is revealed. As a result, the field pilot test in this paper provides theoretical basis and technical support for the efficient development of fractured-vuggy carbonate reservoir.
Paradigm Shift in Completion Limits: Open Hole Gravel Pack in Highly Depleted Reservoirs Drilled with Well Bore Strengthening Technology
Authors: Whaley Kevin , Jackson Phillip J , Wolanski Michael , Aliyev Tural , Muradova Gumru , Eyyubov Arziman , Thomesen Carl , Samadov Hidayat , Kumar Arunesh , Chandran Pavithiran , Majidi Reza
Published: September 2021

Open Hole Gravel Pack (OHGP) completions have been the primary completion type for production wells in the Azeri-Chirag-Gunashli (ACG) field in Azerbaijan for 20 years. In recent years, it has been required to use well bore strengthening mud systems to allow drilling the more depleted parts of the field. This paper describes the major engineering effort that was undertaken to develop systems and techniques that would allow the successful installation of OHGP completions in this environment.

OHGP completions have evolved over the last 3 decades, significantly increasing the window of suitable installation environments such that if a well could be drilled it could, in most cases, be completed as an OHGP if desired. Drilling fluids technology has also advanced to allow the drilling of highly depleted reservoirs with the development of well bore strengthening mud systems which use oversized solids in the mud system to prevent fracture propagation. This paper describes laboratory testing and development of well construction procedures to allow OHGPs to be successfully installed in wells drilled with well bore strengthening mud systems.

Laboratory testing results showed that low levels of formation damage could be achieved in OHGPs using well bore strengthening mud systems that are comparable to those drilled with conventional mud systems. These drilling fluid formulations along with the rigorous mud conditioning and well clean-up practices that were developed were first implemented in mid-2019 and have now been used in 6 OHGP wells. All 6 wells showed that suitable levels of drilling mud cleanliness could be achieved with limited additional time added to the well construction process and operations and all of them have robust sand control reliability and technical limit skins.

Historically it was thought that productive, reliable OHGP completions could not be delivered when using well bore strengthening mud systems due to the inability to effectively produce back filter cakes with large solids through the gravel pack and the ability to condition the mud system to allow sand screen deployment without plugging occurring. The engineering work and field results presented demonstrate that these hurdles can be overcome through appropriate fluid designs and well construction practices.
Modeling Maximum Droplet Size In Gas-Liquid Annular Flow and Liquid–Liquid Dispersed Flow
Authors: Karatayev Kanat , Fan Yilin
Published: September 2021

Hydrocarbon production is commonly associated as the dispersed flow of two and more immiscible phases starting from porous media to surface facilities. In the dispersed flow, one phase is usually dispersed into another dominating phase in terms of droplets. Accurate prediction of the droplet size distribution of a dispersed phase is critical in characterizing complex flow behavior in pipe flows. In the first part of this paper, we provide the analyses of open-source experimental data on the maximum droplet size in gas-liquid annular flow and evaluate the existing theoretical models and suggest an improvement based on the experimental data analyses to predict the maximum droplet size of the entrained liquid droplets in gas-liquid annular flow. In the second part of this paper, we cover the experimental results from the open-source literature data and in-house experimental data to give the general understanding on droplet formation concepts and evaluate the existing predictive models and present a new modeling approach to determine a maximum stable droplet size of the dispersed phase in the liquid-liquid dispersed flow under turbulent flow conditions.
Reconstruction of the Reservoir Fine Structure by Using Scattering Attributes
Authors: Cheverda Vladimir , Lisitsa Vadim , Protasov Maksim , Reshetova Galina , Ledyaev Andrey , Petrov Denis , Shilikov Valery
Published: September 2021

To develop the optimal strategy for developing a hydrocarbon field, one should know in fine detail its geological structure. More and more attention has been paid to cavernous-fractured reservoirs within the carbonate environment in the last decades. This article presents a technology for three-dimensional computing images of such reservoirs using scattered seismic waves. To verify it, we built a particular synthetic model, a digital twin of one of the licensed objects in the north of Eastern Siberia.

One distinctive feature of this digital twin is the representation of faults not as some ideal slip surfaces but as three-dimensional geological bodies filled with tectonic breccias. To simulate such breccias and the geometry of these bodies, we performed a series of numerical experiments based on the discrete elements technique. The purpose of these experiments is the simulation of the geomechanical processes of fault formation.

For the digital twin constructed, we performed full-scale 3D seismic modeling, which made it possible to conduct fully controlled numerical experiments on the construction of wave images and, on this basis, to propose an optimal seismic data processing graph.
Analysis of the Behavior of Petroleum Engineering Student Enrollment in Mexico in the Last 10 Years: Evolution and Challenges
Authors: Cruz-Tun Maria Jose , Flores-Avila Fernando Sebastian
Published: September 2021

This work shows an analysis of the total enrollment, new admissions, graduates and degrees awarded in Petroleum Engineering at Bachelor's level in the last 10 years in Mexico, according to the statistical yearbooks published by the Asociación Nacional de Universidades e Instituciones de Educación Superior (ANUIES), which will allow to know the expected behavior of the student enrollment for the next 5 years. The digital transformation is discussed to propose the strategy of education in the medium and long term.

An analysis is carried out on the study plans of 11 universities that teach Petroleum Engineering and have an active student chapter of the Society of Petroleum Engineers (SPE) in Mexico, to know the subjects taught and detect possible modifications supported by the compression of automation elements such as data analysis and artificial intelligence. Actions taken by other universities in the world for transition from traditional education to an education aligned to new global needs are discussed as well.

Results show that student enrollment exhibits a strong dependence on barrel prices, the higher the price per barrel, the greater the number of new students enrolled. Student ranges from 4,800 to 13,663 at their peak. Derived from the fall in oil prices in 2014, there is an average annual decrease of 12%. If the trend continues to be the same, there will be less than 3,000 Petroleum Engineering students in Mexico by 2025. There are 55 Petroleum Engineering schools in the country, Veracruz and Tabasco together account for 56.5% of graduates nationwide in 2019. Technological innovations and technical challenges should shape the curricula in the Petroleum Engineering degree. It was also detected that the current education contemplates the study of traditional technologies, so it is advisable to align efforts to improve and strengthen the curricula of the universities that already offer the degree, instead of opening new schools.

Mexico's national fields face increasingly complex technical challenges, such as the production of mature fields, unconventional reservoirs, deep-water exploration, and heavy and extra-heavy oils. Current Petroleum Engineering students are the ones who in few years will make important decisions about the direction of the industry, so it is of great interest to know the quality and quantity of them, and focus efforts on addressing deficiencies in fields related to technical challenges.
Analytical Solutions for the Injection of Wettability Modifiers in Carbonate Reservoirs Based on a Reduced Surface Complexation Model
Authors: Lara Orozco Ricardo A. , Okuno Ryosuke , Lake Larry W.
Published: September 2021

The potential of tuned-composition waterflooding to enhance oil recovery from carbonate reservoirs has been widely investigated in the literature. The consensus is that wettability alteration occurs because of the electrostatic interactions between the carbonate rock surface and the potential determining ions, Ca2+, Mg2+, CO32−, and SO42−. Recently, glycine, the simplest amino acid, has also been investigated as a wettability modifier for carbonates that acts similarly as the sulfate ions in brine. The impact of wettability modifiers like glycine and calcite's potential determining ions has been described by surface complexation models (SCM) and the wetting-state of the rock has been related to change of the surface potential. However, determining the relevance of the geochemical reactions is obstructed by the complexity of the SCM. Moreover, the surface potential as a surrogate of the wetting-state of the rock does not correlate with the experimental results with glycine reported in the literature.

The present research analyzed the results of single-phase displacement using a SCM for calcite to determine the important surface complexation reactions. Then, wettability alteration is modeled as a set of anion exchange reactions between wettability modifiers, like SO42− and Gly−, and adsorbed carboxylic acids. Finally, analytical solutions are presented for the coupled two-phase and multicomponent reactive-transport model with anion exchange reactions.
Machine Learning for Multiple Petrophysical Properties Regression Based on Core Images and Well Logs in a Heterogenous Reservoir
Authors: Lin Tao , Mezghani Mokhles , Xu Chicheng , Li Weichang
Published: September 2021

Reservoir characterization requires accurate prediction of multiple petrophysical properties such as bulk density (or acoustic impedance), porosity, and permeability. However, it remains a big challenge in heterogeneous reservoirs due to significant diagenetic impacts including dissolution, dolomitization, cementation, and fracturing. Most well logs lack the resolution to obtain rock properties in detail in a heterogenous formation. Therefore, it is pertinent to integrate core images into the prediction workflow.

This study presents a new approach to solve the problem of obtaining the high-resolution multiple petrophysical properties, by combining machine learning (ML) algorithms and computer vision (CV) techniques. The methodology can be used to automate the process of core data analysis with a minimum number of plugs, thus reducing human effort and cost and improving accuracy. The workflow consists of conditioning and extracting features from core images, correlating well logs and core analysis with those features to build ML models, and applying the models on new cores for petrophysical properties predictions.

The core images are preprocessed and analyzed using color models and texture recognition, to extract image characteristics and core textures. The image features are then aggregated into a profile in depth, resampled and aligned with well logs and core analysis. The ML regression models, including classification and regression trees (CART) and deep neural network (DNN), are trained and validated from the filtered training samples of relevant features and target petrophysical properties. The models are then tested on a blind test dataset to evaluate the prediction performance, to predict target petrophysical properties of grain density, porosity and permeability. The profile of histograms of each target property are computed to analyze the data distribution. The feature vectors are extracted from CV analysis of core images and gamma ray logs. The importance of each feature is generated by CART model to individual target, which may be used to reduce model complexity of future model building. The model performances are evaluated and compared on each target. We achieved reasonably good correlation and accuracy on the models, for example, porosity R2=49.7% and RMSE=2.4 p.u., and logarithmic permeability R2=57.8% and RMSE=0.53.

The field case demonstrates that inclusion of core image attributes can improve petrophysical regression in heterogenous reservoirs. It can be extended to a multi-well setting to generate vertical distribution of petrophysical properties which can be integrated into reservoir modeling and characterization. Machine leaning algorithms can help automate the workflow and be flexible to be adjusted to take various inputs for prediction.
Estimating Formation Tops while Drilling Using Rate of Penetration ROP and Mechanical Specific Energy MSE
Authors: Alshahrani Saeed , Ayadiuno Chris
Published: September 2021

Accurate determination of formation tops while drilling is a critical part of exploration geology workflow. Operational decisions on coring, wireline logging, casing, and final well depth largely depend on it. One of the commonly used methods for picking formation tops while drilling is to correlate the rate of penetration (ROP) of the new well to wireline logs from offset wells where there is no logging while drilling (LWD) data. Picking formation tops based on only ROP from a new well can result in picking the wrong formation tops. To improve the workflow and outcome, this paper proposes the combination of ROP and Mechanical Specific Energy (MSE) for estimating formation tops while drilling. MSE is a measure of the energy required to crush or drill through a unit volume of rock. Because MSE is related to rock strength, it can be correlated to changes in lithofacies and formation tops.

There are three key steps necessary for utilizing mechanical specific energy to estimate formation tops. First, select the input drilling data relevant to the applicable MSE equation. There are several empirical equations in the literature which can be used for estimating MSE. Input data are ROP, Weight on Bit (WOB), Bit Size (BS), Rotation Per Minute (RPM), and Torque (TORQ) from both the offset wells and the new well. Second, utilize a predetermined empirical equation to estimate MSE. Third, correlate MSE and ROP from the new well to both MSE, ROP, and wireline logs from offset wells (where available) to determine formation tops in the new well. Application of the proposed workflow to two wells show 1) distinct bed boundaries, which agree with formation tops picked using wireline logs; (2) that including MSE increases confidence and reliability of the data and makes it easy to identify the different formation boundaries based on the observed features of both MSE and ROP in the new well; and (3) that MSE variations are sensitive to formation strength, which may indicate rock mechanical changes and formation heterogeneity.

This paper presents an alternative method of picking formation tops using MSE and ROP while drilling. The preliminary results based on the two test wells showed over 95% match with those picked using wireline logs of the same new well. As a result, this workflow enhances the ability of geoscientists to correlate subsurface geological features, reduces the uncertainty associated with picking formation tops, casing, and coring depths. Furthermore, it improves the confidence in the result, enhances the quality of operational decisions, and reduces the non-productive time (NPT) and well-cost.
Low Resistivity Pay Carbonates: A Practical Approach to Quantify Water Saturation Using a Modified Archie's Model
Authors: Eyvazzadeh Ramsin , Al-Omair Abdullatif , Kanfar Majed , Christon Achong
Published: September 2021

A detailed description of a modified Archie's equation is proposed to accurately quantify water saturation within low resistivity/low contrast pay carbonates. The majority of previous work on low resistivity/low contrast reservoirs focused on clastics, namely, thin beds and/or clay effects on resistivity measurements. Recent publications have highlighted a "non-Archie" behavior in carbonates with complex pore structures. Several theoretical models were introduced, but new practical applications were not derived to solve this issue.

Built upon previous theoretical research in a holistic approach, new models and workflows have been developed. Specifically, utilizing a combination of machine learning algorithms, nuclear magnetic resonance (NMR), core and geological data, field specific calibrated equations to compute water saturation (Sw) in complex carbonate formations are presented. Essentially, these new models partition the porosity into pore spaces and calculate their relative contribution to water saturation in each pore space. These calibrated equations robustly produce results that have proven invaluable in pay identification, well placement, and have greatly enhanced the ability to manage these types of reservoirs.

This paper initially explains the theory behind the development of the analysis illustrating workflows and validation techniques used to qualify this methodology. A key benefit performing this research is the utilization of machine-learning algorithms to predict NMR derived values in wells that do not have NMR data. Several examples explore where results of this analysis are compared to dynamic testing, formation testing and laboratory measured samples to validate and demonstrate the utility of this new analysis.
An Experimental Study of the Effects of CO2 Injection on Gas/Condensate Recovery and CO2 Storage in Gas-Condensate Reservoirs
Authors: Seteyeobot Ifeanyi , Jamiolahmady Mahmoud , Jaeger Philip , Nasieef Abdulelah
Published: September 2021

The application of non-hydrocarbon gas injection for enhanced gas and condensate recovery (EGCR) is still in a developmental stage as the mixing/interaction between the injected gas and resident reservoir fluid is yet to be extensively understood and the inability to optimize the recovery process has led to limited pilot trials. Carbon dioxide (CO2) injection into gas-condensate reservoirs for improved recovery and CO2 storage provides additional and favorable changes in phase and fluid flow behaviour making it economically more attractive compared to other injection gases. However, to make an informed decision, adequate phase and flow behaviour analysis are required to better forecast the reservoir performance under CO2 injection.

In this research, appropriate experimental phase behaviour, EOS modeling, and unsteady-state flow tests have been conducted to determine the level of CO2/gas-condensate interaction including condensing/vaporizing mechanisms during CO2 Huff-n-Puff (HnP) injection.

A CO2 HnP injection technique was followed to identify the best CO2 flooding conditions. A total of four HnP injection cycles with incremental CO2 volumes of 20, 40, 60, and 80 % of the initial resident fluid volume prior to depletion was considered. CO2 injection pressure and volume are optimized below the saturation pressure. The analysis is based on evaluating the level of interaction between CO2 and resident fluid at the maximum condensate saturation of the corresponding CO2-gas-condensate fluid mixture as determined in a phase equilibria cell. Appropriate experimental phase behaviour and core flood data were generated and analyzed to identify and quantify the level of condensing/vaporizing mechanisms which are vital for adequate optimization of the injection pressure and amount of injected CO2 for both enhanced gas and condensate recovery and CO2 storage purposes. The amount of gas, condensate, and CO2 produced at each core flood stage was recorded. These data allow bridging the gap between conflicting reports on the trend and level of CO2/gas-condensate fluid interactions at pressures below the dew point pressure (Pdew). They also provide a better knowledge of the governing mechanisms during CO2 flooding, which are required for designing appropriate CO2 HnP injection for reservoir engineering applications.
Case Study: Consecutive Failure of Lube Oil Cooler Fans Coupling
Authors: Manikandan Arumugampillai , Anwar Zeeshan
Published: September 2021

Do we analyze on why can even the most reliable turbomachinery are getting failure and stopped? In some cases, it's all about bad installation or design literally. This paper explores the challenges one site had with repeated failure of lube oil fin fan coolers coupling which caused the unit availability of more than 3 months. It outlines the troubleshooting attempts made to remedy this issue, its root cause, and the resulting solution.

This issue occurred at a site with a train configuration of motor driven centrifugal compressors. The plant lube oil system has been configured with 3 trains. Each train has been configured with Main electric motor + Vorecon Gearbox + Low Pressure centrifugal compressor + High Pressure centrifugal compressor. Lube oil system of the train has been configured as 2 lube oil coolers and 2 working oil coolers. Lube oil coolers are having fins with air cooler type. Air is supplied by fin fans and each train has 2 lube oil cooler fans and 2 working oil cooler fans. In total site has 3 trains x 4 fin fans so it has 12 fin fan cooler fans. All cooler fans are driven by electric motor which is coupled with gearbox and gear box is connected with cooler fan.

During normal operation of working oil cooler fan A- stopped rotation suddenly from normal operation. During investigation, motor shaft was found running freely. No movement was seen on cooler fan. Coupling between motor to gearbox was inspected. Coupling is shear plate coupling. Its spacer flexible element were found broken into several pieces. Further investigation revealed that motor coupling hub was moving free axially back and forth due to clearance between motor shaft to coupling hub internal diameter. Motor side Coupling hub bolt hole was found with loss of material and ovality in shape. Hub locking Allen screw was found in damaged condition. Missing materials were noted and broken shear plate materials were found around coupling guard area.

While site team was conducting the investigation on the unit A, similar incident occurred in next unit and other 3 units with 2 days difference between them.

During detailed investigation it has been noted that all motor to gear box coupling are shear plates and shear plates were broken. Coupling hub was found loose and coupling hub locking screw was found broken or partial damage.
Intelligent Plunger Lift: Digital and Cost-Effective Solution to Unlock Gas Potential in a Large Tight Gas Field in China
Authors: Tang JingFei , Audrey Beryl , Lin Jin , Meng Xiang Zhen , Yu Chao , Wang Taiji , Fendt Andrew , Kartoatmodjo Gayatri
Published: September 2021

The field is located in a large gas producing basin in China and has prominent characteristics such as thin formation thickness, low permeability and poor reservoir connectivity. Horizontal drilling associated with multistage hydraulic fracturing has proven to be an effective technique to produce the hydrocarbon in this field.

As the gas wells matures, the production rate starts to decline due to the decreasing of the bottom hole pressure which will prompt a liquid loading issue. A trending gas production loss is up to 150 mmscf in a year due to liquid loading issue alone, which is equivalent to $1.8MM revenue loss. An analytical decline rate showed that the field is declining 3.4% to 4.6% monthly due to the descending of the casing pressure, superimposed with low backflow ratio after hydraulic fracturing, which create a technical and economic challenge to produce effectively. In addition, the location between well pads are remote and far apart. This creates HSE challenge for personnel to go to the well pads, especially during icy road in the winter.

Solid soap stick had been tried as a deliquifications method, unfortunately the result is unsustainable without frequent injection. It is also very much relying on human intervention. Due to that, an alternative liquid lift loading system is introduced in the field. An intelligent plunger lift has been piloted in 12 wells in the field to reduce the liquid loading issue in mid 2021. Apart from the apparent advantages of plunger lift such as mitigation of liquid fallback, zero input energy and low operating/maintenance cost, this system is not desirable to fully close well at downstroke process which comes up with increment of gas production comparing to traditional plunger lift system. One of the major advantages is the real time production data surveillance to enable remote operations based on its intelligence flow control system and downhole sensor.
Use of FDI Data for Comprehensive Evaluation of Horizontal Well Frac Treatments
Authors: Daneshy Ali
Published: September 2021

Effective fracturing of horizontal wells is the key to successfully producing unconventional reservoirs. Correct evaluation of existing created fractures is essential for identification of key treatment variables in the target reservoir and continuous process improvement of the total process.

Measurement and analysis of Frac-driven Interactions (FDI) has become a popular technique for rapid and cost-effective evaluation of existing and new fractures created in horizontal wells for production of unconventional reservoirs. Specific parameters used for their evaluation include detection of the start and end time of FDI during each frac stage, its magnitude, and duration. Another important parameter is observing smoothness of FDI variations with time.

The paper offers specific recommendations for additional measurement and computational steps that can be used for determination of the volume and rate of fluid migration causing the observed FDI.
Applications of Honey Bee Optimization in Reservoir Engineering Assisted History Matching
Authors: Shams Mohamed , El-Banbi Ahmed , Sayyouh M. Helmy
Published: September 2021

Bee colony optimization technique is a stochastic population-based optimization algorithm inspired by the natural optimization behavior shown by honey bees during searching for food. Bee colony optimization algorithm has been successfully applied to various real-world optimization problems mostly in routing, transportation, and scheduling fields.

This paper introduces the bee colony optimization method as the optimization technique in reservoir engineering assisted history matching procedure. The superiority of the proposed optimization algorithm is validated by comparing its performance with two other advanced nature-inspired optimization techniques (genetic and particle swarm optimization algorithms) in three synthetic assisted history matching problems. In addition, this paper presents the application of the bee colony optimization technique in assisting the history match of a full field reservoir simulation model of a mature gas-cap reservoir with 28 years of history. The resultant history matched model is compared with those obtained using a manual history matching procedure and using the most widely applied optimization algorithm used in assisted history matching commercial software tools.

The results of this work indicate that employing the bee colony algorithm as the optimization technique in the assisted history matching workflow yields noticeable enhancement in terms of match quality and time required to achieve a reasonable match.
A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs
Authors: Shi Yue , Mohanty Kishore , Panda Manmath
Published: September 2021

Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.
Diverting from the Status Quo: Leveraging Acid Retardation for Production Enhancement in Offshore Carbonates in UAE
Authors: Luo Yin , Enkababian Philippe , Hrab Leah , Najy Anas , Shokry Ahmed , Berrim Ahmed , Sarsekov Arlen , Sulaiman Andika , Kamaletdinov Bulat
Published: September 2021

With the expanding offshore rig activity in United Arab Emirates leading to an increased number of horizontal wells and longer drains, coupled with changing rock fabrics, it became imperative to diverge from the existing stimulation methods to deliver more consistent and reliable results. These results were achieved via the introduction of single-phase retarded acid (SPRA) and viscoelastic diverting acid (VEDA) to both active and shut-in wells offshore.

The introduction of SPRA and VEDA was possible after extensive laboratory testing including core flow tests, solubility tests, emulsion tendency testing, and corrosion inhibition tests to evaluate and benchmark the performance of these blends in comparison to the existing acid recipes such as plain HCl and polymer-based diverted acid. These tests showed that a combination of SPRA and VEDA would allow maximizing lateral coverage and enhance acid penetration due to the reduced rate of reaction and chemical diversion capabilities from thief zones.

Combining the introduction of SPRA and VEDA with a shift to bullheading and higher pumping rates enabled the delivery of previously unachievable production results at sustainable wellhead pressures or even well revival of shut-in wells. In addition, reduction of acid content for dolomite stimulation was possible due to the implementation of acid retardation, which also allowed protecting wellheads from exposure to higher acid concentrations while bullheading. Treatment parameters such as volumes, rates, and acid/diverter sequence and ratio were then adjusted for optimal wormhole penetration across all zones using a new carbonate matrix acidizing modeling software.

Post-treatment evaluation for the cases of previously shut-in wells has proven the success of the SPRA and VEDA combination. Shut-in wells that were unable to produce sustainably at the required tubing-head pressure (production flowline pressure), were able to produce sustainably with a 100% increase in production compared to prestimulation testing. Similarly, for gas wells, the combination of SPRA and VEDA resulted in a 50% increase in production at a similar bottomhole pressure. In addition, water injectors have also exhibited sustainably increased levels of injectivity compared to prestimulation levels, leading to better sweepage.

The novelty of this paper is the comparison between historical carbonate stimulation results in UAE using plain HCl acid with polymer-based diverted acid and using SPRA with VEDA. It also sheds light on the game-changing solutions that suit the ever-increasing challenges observed in offshore oil and gas wells including well placement, lithology, permeability contrast, and type of hydrocarbon within the various target sublayers.
Understand the Effect of Mud Pulse on Drilling Dynamics Using Big Data and Numerical Modeling
Authors: Shen Yuelin , Bhoite Sameer , Zhang Zhengxin , Chen Wei , Chambon Sylvain , Ibrahim Sameh , Conn David , Smith David , Chen Cen , Mussa Shadi
Published: September 2021

It is common to have measured depth exceeding 20,000 ft for unconventional oil and gas wells. To ensure the pressure pulse can be detected on the surface, many MWD tools have been designed to generate mud pressure pulse with very large amplitude. While the large pressure pulse solved the problem of sending the measured information up to the surface, it creates significant impact on drilling system energy variation and downhole drilling dynamics. This paper focuses on understanding the effects using big data and drilling system modeling.

When a commonly used MWD tool generates mud pulse sequence, it chokes the flow path at designed patterns. This creates mud flow variation in the mud motor below the MWD tool. It also generates axial force variations due to pressure changes, which affect WOB. These changes cause the motor and the bit to experience significant rpm variations. The combined rpm variation and WOB variation often excite more severe axial and lateral shock and vibration. These effects are quantified by thousands of high-frequency downhole datasets and advanced numerical modeling.

In the high-frequency downhole datasets, some of them are obtained from BHAs with MWD tools generating large mud pressure pulse, and some of them are obtained from BHAs with MWD tools generating smaller mud pressure pulse or transmitting the measurements using electromagnetic signal. Statistics of rpm variation and axial and lateral shock and vibrations are compared. It clearly shows that the BHAs utilizing large mud pressure pulse experience more severe torsional, axial, and lateral vibrations. When looking into specific datasets, it showed that mud pressure pulse could cause the motor to lose more than half of its rpm during the flow choking phase. Typical datasets indicate that mud pressure pulse correlates to severe high-frequency torsional oscillation (HFTO) in motorized rotary steerable BHA. An advanced transient drilling dynamics model was built to simulate the whole drilling system subjecting to mud pressure pulse incurred loading conditions. It was found that large-magnitude mud pressure pulse induced more stick/slip and axial and lateral vibrations as recorded in downhole high-frequency data. The increased rotational, axial, and lateral vibrations correspond to more loading variations in the mud motor components and PDC cutters on the drill bit. These variations could cause accelerated damage to the drill bit and downhole tools.

In summary, large mud pressure pulse utilized by some MWD tools introduces significant rpm variation and shock and vibration, which is quantified by big data and further demonstrated by drilling system modeling. The information could help make decisions on BHA design and tool selection to achieve improved drilling performance and reduce the risk of premature tool failure.
Message-Passing-Interface MPI Parallelization of Iteratively Coupled Fluid Flow and Geomechanics Codes for the Simulation of System Behavior in Hydrate-Bearing Geologic Media
Authors: Zhang Jiecheng , Moridis George , Blasingame Thomas
Published: September 2021

The Reservoir GeoMechanics Simulator (RGMS), a geomechanics simulator based on the finite element method and parallelized using the Message Passing Interface (MPI), is developed in this work to model the stresses and deformations in subsurface systems. RGMS can be used stand-alone, or coupled with flow and transport models. pT+H V1.5, a parallel MPI-based version of the serial T+H V1.5 code that describes mass and heat flow in hydrate-bearing porous media, is also developed. Using the fixed-stress split iterative scheme, RGMS is coupled with the pT+H V1.5 to investigate the geomechanical responses associated with gas production from hydrate accumulations. The code development and testing process involve evaluation of the parallelization and of the coupling method, as well as verification and validation of the results.

The parallel performance of the codes is tested on the Ada Linux cluster of the Texas A&M High Performance Research Computing using up to 512 processors, and on a Mac Pro computer with 12 processors. The investigated problems are:

Group 1: Geomechanical problems solved by RGMS in 2D Cartesian and cylindrical domains and a 3D problem, involving 4x106 and 3.375 x106 elements, respectively; Group 2: Realistic problems of gas production from hydrates using pT+H V1.5 in 2D and 3D systems with 2.45x105 and 3.6 x106 elements, respectively; Group 3: The 3D problem in Group 2 solved with the coupled RGMS-pT+H V1.5 simulator, fully accounting for geomechanics.

Two domain partitioning options are investigated on the Ada Linux cluster and the Mac Pro, and the code parallel performance is monitored. On the Ada Linux cluster using 512 processors, the simulation speedups (a) of RGMS are 218.89, 188.13, and 284.70 in the Group 1 problems, (b) of pT+H V1.5 are 174.25 and 341.67 in the Group 2 cases, and (c) of the coupled simulators is 331.80 in Group 3.

The results produced in this work show the necessity of using full geomechanics simulators in marine hydrate-related studies because of the associated pronounced geomechanical effects on production and displacements and (b) the effectiveness of the parallel simulators developed in this study, which can be the only realistic option in these complex simulations of large multi-dimensional domains.
Synergy of Polymer for Mobility Control and Surfactant for Interface Elasticity Increase in Improved Oil Recovery
Authors: Kar Taniya , Firoozabadi Abbas
Published: September 2021

Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.
Using Particle Swarm Optimization to Compute Hundreds of Possible Directional Paths to Get Back/Stay in the Drilling Window
Authors: Cardoso Braga Daniel , Kamyab Mohammadreza , Joshi Deep , Harclerode Brian , Cheatham Curtis
Published: September 2021

One of the responsibilities of a directional driller (DD) is the computation of the current bit position given the last survey station measurement, and with that information calculate the path back to plan if directional correction is needed. Having only a few minutes during a drilling connection to perform these calculations, the DD is limited to compute only a handful of possible paths that will be presented to the Drilling Engineer/Company Man. With this information, the Company Man will decide which path to follow. The present work aims to develop a computer algorithm that replicates the field knowledge of DDs but can compute hundreds of paths in less than one minute. In addition, since the objective of the trajectory correction may differ, the algorithm also can optimize for one of three goals: maximum rate of penetration (ROP), minimum tortuosity in the path, or maximum footage in the drilling target window. The paper presents examples of four different path recommendations in the lateral portion of a horizontal well. The results show the optimum recommended paths for the same position for a specific optimization goal. Finally, a comparison between the running time and number of paths computed is presented. All results were obtained during the validation tests of the algorithm.
Development of Methods for Top-Down Methane Emission Measurements of Oil and Gas Facilities in an Offshore Environment Using a Miniature Methane Spectrometer and Long-Endurance UAS
Authors: Smith Brendan , Buckingham Stuart , Touzel Daniel , Corbett Abigail , Tavner Charles
Published: September 2021

With atmospheric methane concentrations rising, spurring increased social concern, there is a renewed focus in the oil and gas industry on methane emission monitoring and control. In 2019, a methane emission survey at a bp asset west of Shetland was conducted using a closed-cavity methane spectrometer mounted onboard a long-endurance fixed-wing unmanned aerial vehicle (UAV). This flight represents the first methane emissions survey of an offshore facility with a miniature methane spectrometer onboard a UAV with subsequent flights performed. The campaign entailed gathering high-density methane concentration data in a cylindrical flight pattern that circumnavigated the facility in close proximity. A small laser spectrometer was modified from an open-cavity system to a closed-cavity onboard the aircraft and yielded in-flight detection limits (3s) of 1065ppb methane above background for the 2019/2020 sensor version and 150ppb for the 2021 sensor versions. Through simulation, the sensors minimum detection limits in mass flow rate were determined to be 50 kg/h for the 2019/2020 campaign and 2.5kg/h for the 2021 campaigns; translating to an obtainable measurement for 23% and 82% of assets reporting higher than 1 kg/h according to the 2019 EEMS dataset, respectively. To operationalize the approach, a simulation tool for flight planning was developed utilizing a gaussian plume model and a scaled coefficient of variation to invoke expected methane concentration fluctuations at short time intervals. The simulation is additionally used for creation of synthetic datasets to test and validate algorithm development. Two methods were developed to calculate offshore facility level emission rates from the geolocated methane concentration data acquired during the emission surveys. Furthermore, a gaussian plume simulator was developed to predict plume behavior and aid in error analysis. These methods are under evaluation, but all allow for the rapid processing (<24h) of results upon landing the aircraft. Additional flights were conducted in 2020 and 2021 with bp and several UK North Sea Operators through Net Zero Technology Centre (NZTC) funded project, resulting in a total of 18 methane emission survey flights to 11 offshore assets between 2019 and 2021. The 2019 flight, and subsequent 2020/21 flights, demonstrated the potential of the technology to derive facility level emission rates to verify industry emission performance and data.
Temperature Dependence of NMR Relaxation Time in Carbonate Reservoirs
Authors: Shao Wei , Chen Songhua , Hursan Gabor , Ma Shouxiang
Published: September 2021

NMR-based carbonate interpretation models are commonly calibrated using laboratory ambient core NMR measurements. For applying the core calibrated models to downhole NMR logging interpretation, the difference between the NMR responses measured at ambient and reservoir conditions needs to be evaluated. The temperature dependence of NMR relaxation time in high-quality carbonate reservoirs was investigated, and NMR temperature dependence models were determined using data analytic methods (Hursan et al, 2019). This paper focuses on temperature dependence of NMR relaxation time in low-quality carbonate formations.

For more than 95% of the samples investigated, NMR relaxation time shows a positive correlation with temperature. The correlation is similar to that observed in high-quality carbonate rocks but slightly less significant. Temperature dependent correlations for predicting T2GM from a measured temperature to any other temperature are derived from high- and low-quality carbonate rocks independently first, then a unified T2GM correlation is derived including both the high- and low-quality carbonate reservoirs. Predicting T2 distribution from one temperature to other temperatures is achieved using dimension reduction approach involving principal component analysis (PCA) technique. It is found that the T2 distributions at any given temperature for both the high- and low-quality carbonate reservoirs can be predicted robustly from the T2 distributions at the ambient temperature by representing the T2 distributions with principal components (PCs) at the ambient temperature then using these PCs to predict the PCs at a different temperature. The optimal number of PC components depends on the multimodality of the T2 distribution.

This work extends the validity range of a data analytic method that quantifies the temperature dependence of carbonate NMR properties. The new NMR temperature model enables the integration of NMR laboratory studies and dowhole measurements for advanced petrophysical analyses in a wide range of carbonate reservoirs.