bluuebunny/crossref_metadata_2025 huggingface dataset:
Polymer Flooding Simulation Modeling Feasibility Study: Understanding Key Aspects and Design Optimization
Authors: Hidayat Wahyu , ALMolhem Nasser
Published: March 2019

The paper discusses the feasibility study approach of polymer flooding enhanced oil recovery. This work is focused on understanding and quantifying key aspects of polymer flooding and design parameter optimization case. A synthetic reservoir simulation model was employed for the study.

The first stage is to identify and understand key factors that have most significant impact to polymer flooding response. There are eight parameters that are considered in the analysis, such as polymer concentration, polymer thermal degradation, polymer injection duration, and polymer-rock properties (adsorption, residual resistance factor, etc.). The impact of each parameter to oil recovery response was sensitized with its low, mid, and high values. The difference of high to low oil recovery output for all parameters was ranked to determine their significance levels. The top three parameters obtained from the sensitivity analysis are polymer injection duration, thermal degradation, and polymer concentration. Sensitivity cases of polymer injectivity and thermal degradation effects were covered in this work.

The second stage is to determine optimum design parameters of polymer flooding. The most significant parameters from the sensitivity analysis results were considered for further optimization. Three parameters that were selected for design optimization include polymer injection duration, polymer concentration, and well spacing. An optimization workflow with simplex algorithm is linked with a reservoir simulator to generate optimization cases by varying values of optimized parameters. The optimization iteration stops when the maximum value of the objective function, which is the net revenue, is reached. The optimization cycle was done for rock permeability of 500 md and 1000 md.

For a low rock permeability reservoir, the well spacing should be short and a lower polymer concentration is sufficient to provide a good response, in addition to avoiding potential injectivity problem. There should be minimum injectivity problem for reservoir with permeability above 1000 md. It is very important to apply polymer thermal degradation in the simulation model to avoid an optimistic performance prediction. The sensitivity analysis results provide a good understanding on the significance impact of parameters controlling polymer injection response and potential challenges. The optimization approach used in the study aids in investigating many optimization scenario within a short period of time.
Using Cloud Technology to Improve Unconventional Well Planning by Enhanced Collaboration and Automated Engineering Design
Authors: Yuan Zhaoguang , Akpenyi Chukwuka , Carson Dan , Hebert Zachary
Published: March 2019

The successful design and delivery of oil and gas production wells require significant levels of collaboration across multiple domains. The challenges encountered vary widely, and including risk evaluations from offset well analysis, domain-specific workflows and practices, geological concerns and limitations, engineering technology of choice, cost considerations, as well as environmental and safety concerns. Suboptimal levels of collaboration among team members, such as managers, geoscientists, drilling engineers, mud engineers, directional drillers, suppliers, and consultants, often negatively impact the quality or cost of the well.

The application and analysis of a cloud technology in a case study shows how the cost of well planning can be significantly reduced, which enhances team collaboration and improves the process of engineering design. The digital well construction planning solution enables oil and gas operators to manage projects easily by: simplifying task assignment among drilling and operations team members, improving process status tracking, documenting the historical progress of each task, and opening access to industry-leading workflows and engines. This digital well construction planning solution which is deployed in the cloud, includes a project management structure, aiding with the assignment, review, and approval of tasks. Geoscientists and engineers can log in to the digital well construction planning solution, finish specific tasks, and then share the completed tasks with the rest of the project. This enables other team members whose design considerations have dependencies to incorporate holistic and representative design criteria into their own workflows. The process is smooth, concurrent, and evergreen, and all tasks are shared at both the output level and the engineering level. This approach ensures that the project data, workflows, and engineering analysis are always current.

With this new solution, well planning time can be reduced from several days to a few hours. The project manager can easily track the status of each task without back-and-forth phone conversations or e-mails. With unconventional wells, where the well designs are often similar in the same region, template and project copy functions can be used to duplicate designs to the next well and accelerate the design process. After a project copy or template import is executed for a new project, the engineering validations can be produced after being shared. Trajectories can be designed automatically, incorporating anti-collision considerations, geological targets, well surface locations, and other design constraints. Then, well hydraulics, torque and drag analysis, bottomhole assembly (BHA) tendencies, and casing designs are validated to make sure the well is drillable and cost-effective.

This digital well construction planning solution can help operators deliver safe, cost-effective wells on time, and execute high-quality well planning.
Evaluating the Feasibility of Waste Slurry Injection in an Oil Prospect in the Western Desert, Egypt
Authors: Kholy S. M. , Sameh O. , Mounir N. , Shams M. , Mohamed I. M. , Abou-Sayed A. , Abou-Sayed O.
Published: March 2019

Oilfields produce huge amount of waste on daily basis such as drilling mud, tank bottoms, completion fluids, well treatment chemicals, dirty water and produced saltwater. These waste types represent a real challenge to the surrounding environment especially when the oilfield is located within a sensitive environment as in the Western Desert where there are natural reserves and fresh water aquifers. Waste slurry injection has proven to be an economic, environmentally friendly technique to achieve zero waste discharge on the surface over the past years. This technique involves creating a hydraulic fracture in a deep, subsurface, non-hydrocarbon bearing formation which acts as a storage domain to the injected slurrified waste. The objective of this study is to evaluate the feasibility of waste slurry injection in an oil prospect located in the Western Desert. The evaluation includes assessing the subsurface geology, recognizing the possible candidate injection formation(s), and designing the optimum injection parameters.

Both geological and petrophysical data have been used to create the geomechanical earth model for an oil prospect located at Farafra oasis in the Western Desert. This model defines the mechanical properties, pore pressure, and in-situ stresses of the different subsurface formations. Afterwards, a fully 3D fracture simulator has been used to simulate the fracture growth within the candidate injection zone at different injection scenarios. Additionally, the fracture simulator has assessed the containment of the created fracture within the candidate injection formation(s) due to the presence of stress barriers above and below the formation. Finally, the formation disposal capacity has been calculated for each of the injection scenarios using a stress increment model.

The geomechanical earth model shows that there is a good candidate injection zone which is upper/lower bounded by stress barriers. More importantly, it is located deeper than the local fresh water aquifer and thus no contamination is expected to the fresh ground water. In addition, the possible candidate is not a hydrocarbon bearing formation.

A 3D fracture simulator has been used to determine the optimum injection parameters such as: the injection flow rate, the volumetric solids concentration, the slurry rheology and the injection batch duration. These optimum parameters are defined to minimize the stress increment rate over the well life, which ensure the highest disposal capacity and to contain the fracture within the candidate injection formation.

Guidelines to conduct waste slurry injection technique in a new oil prospect that is located within a sensitive environment as in the Western desert are presented in this study. Also, the study highlights that this technique is economic for disposal of the different oilfield waste types in an environmentally friendly fashion.
Novel Empirical Approach to Supercharged Pressure Test Analysis
Authors: Smith Steve , Khairy Hamad , Emma-Ebere Chinwenwa , Ismail Mostafa
Published: March 2019

Objective/ Scope

Supercharged pressures exist when drilling fluid losses (spurt, dynamic and static) invade the near well-bore region and creates a ‘supercharged’ pressure zone that is higher than the reservoir pressure but lower than the wellbore hydrostatic pressure. Due to the overbalanced hydrostatic pressure the fluid invades but cannot be disbursed because of the low mobility of the rock. This creates a near well-bore region with pore pressures between hydrostatic (wellbore) and reservoir pressure. This typically occurs in low mobility formations where the dispersion of the invaded drilling fluids is not efficient. Determining true reservoir pore pressure in these conditions is difficult for formation pressure testing tools (FPT's) which measure elevated pressures above true reservoir pressure in these conditions. Analyzing the change in measured pressures from repeated tests using FPT's may help estimate the true formation pressure.

Method, Procedure, and Process

One characteristic indication of supercharging is successive pressure build-up tests (after small drawdown volumes) that stabilize at lower pressures with each subsequent test as more supercharging fluid is removed from the near well-bore region. The successive decrease in build-up pressure as a function of volume can provide information on the dynamic pressure environment in the near wellbore zone and the reservoir pressures further from the wellbore. Plotting the pressure drop as a function of fluid volume removed from the formation and fitting an exponential decay curve to the data provides an estimate of the reservoir pressure. The curve is optimized using a regression algorithm to find a best match. Because one of the unknown variables is the desired formation pressure, a range of formation pressures are evaluated and a χ-squared error function is minimized, thus approximating the true reservoir pressure.

Results, Observations, Conclusions

Numerical simulation models with known formation pressures were set-up with a static supercharged near well-bore environment and various pressure tests were conducted. Analysis was performed on a number of tests to optimize the regression algorithm. The optimized regression provided an indication of the reservoir pressure within 2% of the simulated value. Real data examples were also analyzed with good results.

Novel/ Additive Information

This analysis technique provides a novel empirical method for estimating reservoir pressures in supercharged environments by investigating the change in build-up pressures in successive tests. The analysis can be accomplished with pressure measurement data from standard FPT's. Furthermore, the individual pressure tests do not need to stabilize because the change in pressure is used nor do the pressure tests need to measure the true reservoir pressure because it is determined by a regression analysis.
Three Dimensional Compositional Variation in Gas Condensate Reservoirs
Authors: Kabir Akim , Ahmed Mahbub , Elew Dhaher
Published: March 2019

Gas condensate reservoirs are a major player in the oil and gas industry. Proper understanding of reservoir fluid composition and their spatial distribution helps define our resource base and forecast field production profile. In a gas accumulation with substantial vertical span, a composition gradient is expected, where heavier molecules gravitate towards the bottom end and lighter components' concentration increases towards the top of the column. However, in the literature some investigators have reported both condensate content and heavy hydrocarbon components decrease with increasing depth and temperature. Their observations appear to be contradicting the expected gravity driven compositional gradient as per thermodynamic equilibrium.

In this paper, we have done an integrated areal and vertical composition trend analysis of some gas condensate reservoirs across a big area i.e. a three-dimensional trend analysis. Field wide areal and vertical reservoir anhydrite content has been mapped. The areal composition gradient that defies expected gravity driven composition gradient, while honoring vertical thermodynamic equilibrium has been reconciled. Post depositional fluid/rock thermochemical reaction and low areal diffusivity has resulted in this areal variation. In-situ H2S generation has been enhanced where reservoir deepens and temperature increases, thus overcoming the activation energy hump. H2S concentration increase has happened at the expense of the hydrocarbon concentration as per the thermochemical reaction stoichiometry. It was found that the vertical compositional gradient is consistent with thermodynamic equilibrium calculations. Some observed trend anomalies have been explained using rock composition and geological information.

Thus, a three dimensional compositional gradient was deciphered for reservoirs with such behavior. The aim of this study has been to provide a better quality forecast for reserves, rate, recovery and composition mix for gas condensate fields.
Acid Fracturing Was Selected to Stimulate the Potential Production in Low Permeability Reservoirs in Ahdeb Oilfield, Iraq
Authors: Xiao Yong , Wang Hehua , Guo Jianchun , Lu Lize , Cheng Yi , Chen Mengting , Fan Fengying , Xue Heng
Published: March 2019

The low permeability reservoir of Ahdeb field discovered in the 80's, has more than 250 active wells with low initial production and rapid decline compared to other reservoirs. Matrix acidizing is the main stimulation method to recover and enhance production performance in Ahdeb oilfield, but short-distance deblocking acidizing can't communicate with the deep reservoir, and it is impossible to expand the effective seepage radius. Therefore, High reservoir heterogeneity, low permeability, poor pore pressure necessitates the move from conventional matrix stimulation to acid fracturing technology targeting better fracture conductivity and deep penetration for effective productivity and recovery enhancement.

The acid fracturing feasibility research shows that the interlayer characteristics, lithologic barrier, stress barrier and oil-water relationship of the low permeability reservoirs are favorable for fracture initiation, expansion and geometry control. Acid fracturing is one of the best ways to stimulate the potential production in low-permeability reservoirs of the Ahdeb oilfield. The acid fracturing optimization includes fracture conductivity, fluid system and fracturing parameters. Pad acid fracturing and gel acid with multi-stage alternating and closed acid fracturing are the suitable technologies for low permeability reservoir stimulation.

An experiment well has been simulated and designed, and the expected production increase is 1.5 times. Base on this paper's research, a wide-scale development strategy will be planned, and many wells will be stimulated for increase the production performance.
Proactive Utilization of ESP Performance Monitoring to Enhance Productivity
Authors: Al-Sadah Hashim , Abo Khamseen Mohannad , Al-Ghamdi Abdullah , Fardan Ali
Published: March 2019

As the electric submersible pump (ESP) population increases, the requirement for continuous operation is required to ensure optimum oil sweep rather than depending on fewer number of ESPs. ESP outages, shutdowns and underperforming pumps have to be minimized to reduce operational cost and deferred production. In efforts to reduce pumps downtime, ESP monitoring operations were centralized in a production surveillance and optimization center. This paper illustrates the practices followed in the hub to enhance productivity, by preventing ESP trips and failures, and conducting optimization initiatives through collaborative efforts with different parties.

By remote monitoring of real-time data of downhole sensor readings and surface data, the hub can identify ESP units operating in conditions that could lead to shutdowns and are identified to be preventable ESP trips. By capturing and predicting the downtime events, the objectives of reducing ESP downtime and production deferral is achieved. The hub monitors the individual unit's parameters with its operational confines to ensure that the ESP is running within the preferred boundaries to preserve the equipment's electrical and mechanical health. The observed conditions are referenced against the design and actions are taken accordingly to avert unnecessary trips.

Upon the deployment of ESP monitoring, many benefits were realized ranging from improved asset performance to raising efficiency of manpower usage besides saving time. Deferred production was avoided through eliminating preventable trips under ESP monitoring. This practice not only prevents ESP downtime, but also has the goal of improving ESP efficiency levels, regarding motor and pump performance.

Proactive measures are crucial in ESP production operations. In events where a probable ESP trip is predicted and actions are taken to optimize its operating conditions to prevent the trip, the number of ESP outages at the field level is reduced, thereby helping to sustain a healthy ESP well life cycle.
Fluid Characterization Using a Novel Formation Testing Technology, A Case study
Authors: Padhy Girija Shankar , Kasaraneni Pruthvi Raj , Al-Rashidi Tahani , Tagarieva Larisa , Abba Abdessalem
Published: March 2019

Carbonate Reservoir characteristics and fluid properties can vary among multiple layers within the same stratigraphic unit. The objective of this case study is to emphasize the added values of integrating the data from a newly introduced formation testing technology along with open hole logs and core data to enhance the understanding of the Minagish Ooilte reservoir permeability distribution and fluid typing.

The methodology implies the first time application of the newly introduced formation testing techology external mounted quartz pressure gauge and fluid typing sensors (density, viscosity, resistivity, capacitance, pressure and temperature), which could minimize reservoir fluid samples contamination and later validated by comparison to laboratory analysis results. The fluid sampling operation was conducted in different reservoir units with varying mobility values where the tested zones were selected based on the pressure pretests done prior to the sampling deployment. The success criteria to evaluate the pressure measurements capability of the new techgnology was met as set by the operator to have accuracy within 0.1psi range for two build-up in pretest at the same point. The data was integrated with open hole logs and laboratory measurements to provide a comprehensive formation evaluation and conclusive reservoir characterization after validation of the permeability.

Heterogeniety in permeability measured/captured through RFT-tool was helpful to understand the reservoir flow capacity at the well location and subsequently select the right perforation intervals. Multiple fluid samples collected during this job aided in understanding the compositional variation with depth in the reservoir. Conjoining fluid variation with flow capacity of the reservoir was immensely useful to understand the true oil potential of the well and eventually select right production allowables. Production performance and productivity of the resulting well obtained after completing in the appropriate interval is better than other wells in the near vicinity.

The high well performance and productivity reflect the value of the information provided by the novel formation testing technology sonde helped, as it achieve the well objectives, design the appropriate completion and most importantly resolve many Minagish Oolite reservoir characterization uncertainties in a timely efficient operation.
Developing a Polymer Scale Inhibitor for a Combined Fracture and Inhibitor Squeeze Treatment for High-Temperature Reservoirs
Authors: Chen Ping , Rawlins Scott , Hagen Thomas , Huijgen Martijn , Yue David Zhiwei , Hamam Mohammed , El Hajj Hicham , Al-Ghamdi Tawfik
Published: March 2019

A strategy combining fracturing and downhole scale inhibitor squeeze treatments was employed in an extremely tight high-temperature gas reservoir (200°C) with calcite and sulfate scaling problems. Challenges included developing a scale inhibitor that is thermally stable at this high temperature, fully compatible with the fracture fluid used, extremely beneficial with a low minimum effective concentration, with good adsorption/desorption properties for a long squeeze treatment life. Literature survey verifies that few reports are published discussing application of a combined fracture and downhole scale inhibitor squeeze treatment under such high-temperature reservoir conditions.

Multiple laboratory tests were performed to qualify the scale inhibitor, including inhibitor dynamic tube blocking, static beaker, and fracture fluid property testing. Standard inhibition tests were adapted to confirm tests were designed to confirm that the scale inhibitor was thermally stable under application conditions (i.e., the scale inhibitor was blended with the fracture fluid (including breaker) at given concentrations and aged together at 200°C for a certain period). The aged scale inhibitor sample was then tested for its performance against scale and results compared to the unaged inhibitor sample. Further tests were designed for fracture fluid rheology and breaking time with the blended scale inhibitor to help ensure the scale inhibitor was fully compatible with the fracturing fluid and would not interfere with its properties.

Laboratory test results demonstrated that the scale inhibitor is fully compatible with the fracturing fluid and formation brine. An extremely low minimum effective concentration of the scale inhibitor was determined to be 5 ppm with the aged and unaged scale inhibitor samples. With the addition of the scale inhibitor, the breaking time and rheology property of the fracture gel met all application requirements. The chemistry of the amine-containing polymer inhibitor and advantages of using this chemistry as a downhole squeeze product are discussed. Successful field treatment with the combined scale inhibitor and fracture fluid was conducted.

A new scale inhibitor chemistry was developed for a high-temperature reservoir for combined fracture and downhole inhibitor squeeze treatments.
Overmature and Vitrinite-Barren Source Rocks: A Novel Thermal Maturity Parameter
Authors: Henderson Sebastian , Ghassal Bandar
Published: March 2019

Standard Rock-Eval pyrolysis is commonly used to estimate the thermal maturity of source rocks. However, measuring the maturity of overmature samples with high Tmax values (> 470°C) is very challenging due to the weak development of S2 peaks. Moreover, measuring the vitrinite reflectance of dispersed organic matter high thermal maturity samples is commonly used when the Tmax (°C) of the sample is unreliable. Nevertheless, vitrinite assemblages are very rare/absent in marine samples particularly in marlstones or pre-Carboniferous source rocks. The current study addresses a new thermal maturity parameter that used the carbon monoxide CO released during Rock Eval-6 oxidations.

A total of 14 marine source rock samples were analyzed by Rock Eval-6 to assess their generative potential. The samples range in Tmax from 420° to 475°C indicating wide thermal maturity range from immature to overmature. During Rock-Eval analyses, CO released from the kerogens and their peak temperature (Tco) was recorded. A strong positive correlation was observed between the Tmax and the Tco (r=0.94). Note that the CO is released from the organic oxygen compounds that are none/or less liable compared to pure hydrocarbon compounds. Thus, Tco is more reliable than Tmax in assessing high thermal maturity levels.

The new method provides a robust and quick interpretation of high thermal maturity source rocks especially for pre-Carboniferous samples that lack a well-devolved S2 peak. Carbon monoxide generation is not affected by carbonate decay to CO2 and is also not affected by contamination used in drilling fluids. Testing of different source rocks is needed to establish this further and to improve the trend observed.
Beam Pump Dynamometer Card Classification Using Machine Learning
Authors: Sharaf Sayed Ali , Bangert Patrick , Fardan Mohamed , Alqassab Khalil , Abubakr Mohamed , Ahmed Mahmood
Published: March 2019

A beam or a sucker rod pump is an artificial-lift pumping system using a surface power source to drive a downhole pump assembly. A beam and crank assembly creates reciprocating motion in a sucker-rod string that connects to the downhole pump assembly. The pump contains a plunger and valve assembly to convert the reciprocating motion to vertical fluid movement. A dynamometer is a diagnostic device used on sucker rod pumped wells that measures the load on the top rod and plots this load in relation to the polished rod position as the pumping unit moves through each stroke cycle.

The analysis of the dynamometer card data delivers valuable insights on the status of the pump and indicates if future actions are required. In practice, the load versus displacement plot shape can be visually categorized in different classes where each shape has a specific meaning and indicates certain operating conditions. Machine learning algorithms are computing systems that learn to perform tasks by considering examples, generally without being programmed with any task-specific rules. During a period of approximately two (2) months, we collected 5,380,163 different cards from 297 beam pumps deployed in the Bahrain Field using the Supervisory Control and Data Acquisition (SCADA) system with an Open Platform Communication (OPC) interface. 35,292 cards are manually labelled by experts into twelve (12) classes. The dataset is split into 80% training and 20% holdout datasets. A training dataset is split into 5-fold cross validation. Different machine learning algorithms are evaluated predicting pump card class and their performance is compared. The top performing model, Gradient Boosting Machines (GBM) Classifier, achieves 99.98% accuracy in cross validation and 100% accuracy on holdout dataset without any extensive feature engineering.

This paper explains the steps taken to improve surveillance of beam pumps using dynamometer card data and machine learning techniques and the lessons learned from executing the first Artificial Intelligence (AI) project within Tatweer Petroleum.
A Novel Dynamic Production Splitting Method Based on the Catastrophe Theory
Authors: Mi Lidong , Hu Xiangyang , Jia Ying , Liu Qianjun
Published: March 2019

Multilayer commingled production is a common means for the development of multilayer tight gas reservoirs. The understanding of the production from each formation plays a significant role in the fine description of reservoir and remaining gas distribution, especially for the water-producing gas wells.

In this paper, a dynamic method for production splitting of water-producing gas wells is introduced. First, a dynamic permeability calculation method is established based on the relative permeability curve and the water-gas ratio. Then, based on the catastrophe theory, a dynamic production splitting method considering the influence of various factors (reservoir characteristics, development characteristics and geological characteristics) is established. Finally, a dynamic production splitting system is developed of multi-layer combined production gas wells.

The verification of production test data shows that the dynamic splitting method can better fit the production test results and accord with the actual production situation. This novel method can be used to split the production for the multilayer combined production well.
Application of Renewable Energy in the Oil and Gas Industry
Authors: Saadawi Hisham
Published: March 2019

The oil and gas industry will continue to play an essential role in meeting the growing world energy demand for decades to come. A fact sometimes overlooked is that the industry is also a major consumer of energy and a contributor to Greenhouse Gas (GHG) emissions.

In recent years, there has been increasing interest in the use of renewable energy in the oil industry. Various technologies are used to produce renewable energy, from solar radiation to harnessing the power of the wind and sea.

The application of different types of renewable energy in oil and gas fields is reviewed. The advantages and limitations of each technology are discussed. This paper presents the state of the art on current and potential applications of the different technologies of renewable energy in the oil and gas industry.

The paper demonstrates that using renewables offer many advantages including saving hydrocarbon resources, minimizing the oil industry's GHG emission and enhancing its public image.
Combined Low Salinity Water Injection and Foam Flooding in Sandstone Reservoir Rock: A New Hybrid EOR
Authors: Shabib-AsL Abdolmohsen , Abdalla Ayoub Mohammed , Abdalla Elraies Khaled
Published: March 2019

To date, several methods have been designed and implemented either individually or as combination to increase oil recovery. The combined methods also called hybrid Enhanced Oil Recovery (EOR) pose great challenges in the oil and gas industry. This is also confirmed from the Industry Technology Facilitator (ITF)'s Gulf Cooperation Council (GCC) Technology roadmap that pinpointed hybrid EOR as the top challenge. This work investigates the potential of a new hybrid EOR method termed Low Salinity Water Assisted Foam flooding (LSWAF). Typically, it consists of injecting Low Salinity Water (LSW) followed by an alternated injection of a Surfactant Aqueous Solution (SAS) and CO2 gas. The selection of LSW was based on its ability to produce significant changes of rock wettability. While the SAS was made, so that it results in a considerable reduction of IFT and produce foam that will remain considerably stable in the presence of oil under reservoir conditions. The selection of the best LSW and SAS followed a screening phase whereby formulations of different ion compositions and salinities were prepared and their performances were compared against each other. Tests were carried out by using two types of light crude oil with different Total Acid Number and Base Number, namely Crude oil A and B. In terms of changes in wettability, for both crude oils A and B, the experimental results revealed that much changes were experienced by the LSW of KCl composition followed by that of NaCl, then CaCl2, MgCl2, Mix composition, and finally the formation water (FW) that presented negligible changes. The changes with crude oil B were greater than crude oil A. However, for crude oil A and B, the core flooding experiments showed that the highest residual oil recovery was achieved by the LSWAF of KCl composition (87.45% of OOIP) compared to the MgCl2 and FW.
Hydrogen-Deuterium Exchange Between Rock Minerals and D2O
Authors: Zainuddin W N , Xie Sheena X. , Kechut Nor Idah , Kantaatmadja Budi P. , Singer Philip M. , Hirasaki George J.
Published: March 2019

Nuclear magnetic resonance (NMR) T2 spin-spin relaxation is a well-established technique in petrophysics labs for quantifying bound/free water and pore-size distribution of reservoir rocks. The method has also been used to measure oil and water saturations, and to characterize wettability alterations for oil/water/rock systems. The T2 relaxation distribution measured by hydrogen NMR is the sum of contributions from both oil and water in the core. It is therefore necessary to separate the T2 signals of oil from water. Since deuterium oxide (D2O) does not have a NMR signal at the resonance frequency for hydrogen, brine made with D2O is commonly used as the aqueous phase to determine the oil saturation from NMR.

The objective of this work was twofold: (1) to validate the oil saturations in the core with NMR T2 relaxation at connate water saturation (before and after aging) and residual oil saturation after waterflooding; and (2) to investigate the potential hydrogen-deuterium (H-D) ion exchange between rock minerals and D2O. Berea sandstone cores were used along with the crude oil from one of the fields in the Sarawak Basin, Malaysia. The aqueous phase was a synthetic brine made with either deionized water or D2O.

Two cores containing the crude oil with D2O brine as the connate (or initial) water were aged at 75eC for up to 65 days. During the aging period, the cores were scanned three times for T2 measurements. The measured T2 volumes (supposedly a measure of the oil volume) of the two cores kept increasing as the aging time increased. However, mass balance indicated that the oil saturation was the same before and after aging. The inconsistent oil saturation measured by NMR indicated that there was H-D ion exchange between the rock minerals and D2O. The cores were then flooded with the fresh D2O brine, after which the residual oil from NMR agreed with that from mass balance, indicating that the fresh D2O had replaced the connate D2O brine affected by H-D ion exchange.

Additionally, two cores fully saturated with D2O brine were also measured by NMR before and after aging at 75°C, again confirming the H-D ion exchange between the rock minerals and D2O. Finally, the mixture of the crude oil and D2O was measured by NMR before and after aging at 75°C, indicating that the interactions between the crude oil and D2O increased the T2 relaxation time. The total T2 volume was not affected.

This work provides evidence of H-D ion exchange between rock minerals and D2O at elevated temperature. It is recommended that such interactions between the rock minerals and D2O brine be considered for related tests, especially when elevated temperature is involved.
Diagnosing and Predicting Problems with Rod Pumps using Machine Learning
Authors: Bangert Patrick
Published: March 2019

Approximately 20% of all oilwells in the world use a beam pump to raise crude oil to the surface. The proper maintenance of these pumps is thus an important issue in oilfield operations. We wish to know, preferably before the failure, what is wrong with the pump. Maintenance issues on the downhole part of a beam pump can be reliably diagnosed from a plot of the displacement and load on the traveling valve; a diagram known as a dynamometer card. We demonstrate in this paper that this analysis can be fully automated using machine learning techniques that teach themselves to recognize various classes of damage in advance of the failure. We use a dataset of of 35292 sample cards drawn from 299 beam pumps in the Bahrain oilfield. We can detect 11 different damage classes from each other and from the normal class with an accuracy of 99.9%. This high accuracy makes it possible to automatically diagnose beam pumps in real-time and for the maintenance crew to focus on fixing pumps instead of monitoring them, which increases overall oil yield and decreases environmental impact.
Improved Predictions in Oil Operations Using Artificial Intelligent Techniques
Authors: Hassan Amjed , Al-Majed Abdulaziz , Mahmoud Mohamed , Elkatatny Salaheldin , Abdulraheem Abdulazeez
Published: March 2019

Oil is considered one of the main drivers that affects the world economy and a key factor in its continuous development. Several operations are used to ensure continues oil production, these operations include; exploration, drilling, production, and reservoir management. Numerous uncertainties and complexities are involved in those operations, which reduce the production performance and increase the operational cost.

Several attempts were reported to predict the performance of oil production systems using different approaches, including analytical and numerical methods. However, severe estimation errors and significant deviations were observed between the predicted results and actual field data. This could be due to the different assumptions used to simplify the problems. Therefore, searching for quick and rigorous models to evaluate the oil-production system and anticipate production problems is highly needed.

This paper presents a new application of artificial intelligent (AI) techniques to determine the efficiency of several operations including; drilling, production and reservoir performance. For each operation, the most common conditions were applied to develop and evaluate the model reliability. The developed models investigate the significance of different well and reservoir configurations on the system performance. Parameters such as, reservoir permeability, drainage size, wellbore completions, hydrocarbon production rate and choke performance were studied. The primary oil production and enhanced oil recovery (EOR) operations were considered as well as the stimulation processes. Actual data from several oil-fields were used to develop and validate the intelligent models.

The novelty of this paper is that the proposed models are reliable and outperform the current methods. This work introduces an effective approach for estimating the performance of oil production system and refine the current numerical or analytical models to improve the reservoir managements.
Experimental Study to Estimate CO2 Solubility in a High Pressure High Temperature HPHT Reservoir Carbonate Aquifer
Authors: Zaidin Mohd Fakrumie , Kantaatmadja Budi Priyatna , Chapoy Antonin , Ahmadi Pehzman , Burgass Rod
Published: March 2019

The X field is one of PETRONAS's Research & Development (R&D) initiative plans involving separation of high CO2-Hydrocarbon gas and CO2 storage in offshore Malaysia. The X field is a high pressure high temperature (HPHT) carbonate reservoir with a temperature of 423 K and pressure of 36.0 MPa with about 500 m of gas column. It was chosen as a candidate due to its well and reservoir data completeness. The plan is technically challenging as it involves re-injecting produced supercritical CO2 back into an aquifer reservoir for permanent storage. Recently acquired X field DST data indicates the presence of CO2 in the aquifer, up to a level nearing saturation. Information of the initial CO2 concentration level in the aquifer reservoir is critical to ensure the success of the CO2 injection. Predictions on this initial CO2 solubility have been made using available well data, however the reliability of the results has to be validated by an experimental study. Therefore, an extensive experimental approach to measure initial CO2 solubility in the X field aquifer reservoir has been conducted. As pressure, temperature and salinity are the important key parameters that influence CO2 solubility, detailed information about X field gas and aquifer brine compositions are well determined prior to the solubility measurement. Utilizing lab facilities at Heriot-Watt University (HWU), measurements were conducted at T=423.15 K and pressure at 36.0 MPa to mimic the X field aquifer conditions. The experimental results obtained are compared against available literature data, Duan Model and sCPA-EoS model and reasonable agreements were observed. Experimental results indicated that the X field aquifer is not fully saturated with CO2 and it could accommodate an additional 6 mol% of CO2 dissolved in the brine. In addition, approximately 6 mol% of hydrocarbon will be recovered from the same aquifer system as a result of CO2 injection due to the CO2-Hydrocarbon displacement. This paper details lab measurements of initial CO2 solubility in the X field aquifer, including preparation, experimental procedure, results and discussion as well as suggested future works. Reservoir simulation incorporating the experimental data obtained from this study is necessary and recommended, for getting a full picture of the CO2 injection program for the current Carbon Capture Utilization & Storage (CCUS) project.
Next Generation Gas Emission Monitoring System
Authors: Uyanik Ilyas , Wesley Avinash
Published: March 2019

During drilling or production operations, poisonous, highly flammable hazardous gases can be released into the environment. A next-generation gas emission monitoring system monitors gas leaks and can help the oil and gas industry improve workplace safety. The initial design, architecture, and development of a real-time monitoring and surveillance system consisting of drones capable of performing autonomous aerial inspections is discussed. This system monitors and reports the spatiotemporal evolution of hazardous gas clouds, such as H2S, CH4, and CO2, in the oil and gas facilities in real time and provides necessary actions for a safe operation. The proposed monitoring system is compared to the traditional monitoring approach where sensors are placed near the ground. This work is a significant improvement from the authors’ previous work leveraging state-of-the-art machine learning technologies to create smart drones capable of making intelligent decisions involving gas leak monitoring.
Validation of High Pressure Resin Impregnation Technique for High Resolution Confocal Imaging of Geological Samples
Authors: Hassan A. , Yutkin M. P. , Chandra V. , Patzek T. W.
Published: March 2019

In this paper, we present a procedure for high pressure resin impregnation of microporous rock. This procedure produces the high- quality pore casts that reveal the fine details of the complex pore space of micritic carbonates. We carefully test our resin impregnation procedure and demonstrate that it renders the high resolution, 3D confocal images of pore casts. In our work, we use silicon micromodels as a reference to validate the key parameters of high-pressure resin impregnation. We demonstrate possible artifacts and defects that might develop during rock impregnation with resin, e.g., the resin shrinkage and gas trapping. The main outcome of this paper is a robust protocol for obtaining the high-quality epoxy pore casts suitable for rock imaging with Confocal Laser Scanning Microscopy (CLSM). We have implemented this protocol and provided the high resolution, three-dimensional (3D) imagery and description of microporosity in micritic carbonates.
Complex Settings Need Complex Equations – Comparison Between Numerical and Semi-Quantitative Geomechanical Solutions
Authors: Bahuguna Somessh , Talreja Rahul
Published: March 2019

Simplified semi-quantitative equations are used in 1D geomechanics workflows to predict the rock’s behavior during drilling and production. While such methods allow for getting a time- efficient solution, it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. We lose the ability to predict full field behavior in response to drilling and production activities. For example, when constructing a field-wide drilling plan or a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on the stresses. It generates solutions which are more akin to reality.

In this paper, this difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in the study is quite complex – an amalgamation of high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using both a well-centric approach and a full field-wide 3D numerical solution.

It is clearly observed that field-based approach provided us more accurate estimation of overburden stresses, variation of pore pressure across the field, impending changes in stress magnitudes and its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the estimated well-centric overburden at the toe of deviated well at reservoir level is lower by 0.21gm/cc (~1.75ppg~0.9psi/ft) as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is primarily due to effect of fault on stresses (both magnitude and azimuth). Stress states of 4 faults were assessed and all 4 faults are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, shows them to be stable.

By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.
Evaluation of a New Environmentally Friendly Flowback Surfactant and Its Application to Enhance Oil and Gas Productivity
Authors: Rabie Ahmed , Zhou Jian , Qu Qi
Published: March 2019

Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity.

In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated.

The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.