bluuebunny/crossref_metadata_2025 huggingface dataset:
Mature Oilfield Production Surveillance and Optimization Using Clamp-On Sonarflow Surveillance
Authors: Hussein Ahmed , Alqassab Mohammed , Atef Hazem , Sirdhar Siddesh , Alajmi Salem Abdullah , Aldeyain Khaled Waleed , Hassan Mohamed Farouk , Goel Harrish Kumar
Published: November 2019

Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance "Nodal analysis" and "Live Flow Line Surface Network Model".

A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization.

The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well.

The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the "averaging" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.
Supervised Machine Learning in Predicting Multiphase Flow Regimes in Horizontal Pipes
Authors: Alhashem Mayadah
Published: November 2019

The petroleum industry has been undergoing transitional changes that were mandated by the high competition in the business. Making decisions and engineering approaches grew from being trial- and-error, educated guesses, well-studied designs, to finally creating advanced and well developed models and simulations. Yet, the development of approaches has been and will always be rapidly ongoing. In order to stay competitive, the approaches must be constantly improving.

This study was performed as a proof-of-concept to assess and prove the practicality of using supervised machine learning (ML) techniques to predict multiphase flow regimes in horizontal pipes. The flow is comprised of air, water, and oil. The input features used were water cut (the percentage of water), gas superficial velocity, and liquid superficial velocity. The predicted output was one of six possible flow regimes. The algorithms assessed in the study were Decision Tree, Random Forest, Logistic Regression, Support Vector Machine (SVM), and Neural Network Multi-Layer Perceptron (MLP). According to the results, the best candidate for the dataset is to use the random forest algorithm with a high accuracy of 90.8% and low training time (0.13 seconds) in case of increasing the size of the data and features.

All the predictive algorithms can be easily improved in accuracy by increasing experience, either increasing the size of the dataset or addition of relevant features. The trained model and logic can be applied in industry by automating flow control or installing prediction and mitigation systems in pipelines and field operations.
Oil Spill Detection, Thickness Evaluation with Radar, Optical and Infrared Sensors
Authors: Vinther Morten Loell
Published: November 2019

Leveraging dry wave monitoring technology to detect oil spills can contribute to quicker and more cost-effective oil spill rescue operations than leveraging in-water solutions or laser technology. Using X-band radar-based technology in combination with infrared-cameras is a proven method which supports both oil-spill surveillance and response. This technical paper highlights the physical material properties that make oil spill detection possible with a combined system of x-band radar technology and infrared cameras.
Challenges of Ethylene Process Compressor Trains: From Design to Start-Up and Operability
Authors: Corbò Simone , Calosi Mirco , Acquisti Gianni
Published: November 2019

This technical presentation features various challenges that a turbomachinery OEM and the end users face with compressor trains in Ethylene Process, from the initial design phase, to the plant commissioning and operation of these machines.

The presentation illustrates also the possible technical solutions, such as special coatings to prevent fouling in charge gas compressors, to help end users to reduce the operating cost and risk of production loss. The implementation of compact solutions, which helps the charge gas and ethylene compressors to deliver a higher-pressure ratio in one casing, results in lower number of bodies with same compression sections and consequently simplified installation and lower costs. Technical and special design features will be illustrated during the presentation.

A smoother operation of the units can be offered building a dynamic model capable to simulate the behavior of the drivers, compressors and process plant items, in stable operating conditions and transient phases. With such model, any potential criticality of the interactions between process and compressors can be identified up-front in a simulation environment, minimizing risks at site, during commissioning and first start-up.

The impact of fouling on ethylene plant equipment can be substantial. The high possibility of gas polymerization occurring in the cracked gas compressor can lead to efficiency loss and unplanned outages with associated lack of production. An advanced stage-by-stage water injection system coupled with fully removable nozzles during compressor operation and an efficiency monitoring and control system, will reduce operating cost and risk of production loss by providing operators with continuously updated equipment performance. This information can also be integrated with the analytic that performs an early detection of steam turbine fouling phenomena.

Finally, the authors present few case studies where the above strategies were successfully implemented.
Reaching Target Depth with Zero NPT in an HPHT Tight Gas Well: A Case for Automated Managed Pressure Drilling
Authors: Khalid Ali , Ashraf Qasim , Luqman Khurram , Hadj-Moussa Ayoub , Sheikh Daoud , Zafar Saad
Published: November 2019

As shallower reservoirs are driven to depletion the world over and the world energy demand keeps growing at a steady pace, operators explore for deeper horizons within current fields in hope of making significant discoveries. Deeper exploration in most fields entails significant risk, and a much higher cost per well.

With deeper drilling depths comes tougher drilling challenges, mostly arising from higher pressures and higher temperatures at those depths. High-pressure, high temperature (HPHT) wells present numerous drilling risks, often including influxes while drilling into over-pressured formations, insufficient mud weight and bottomhole pressure control due to bottomhole density reduction with high temperatures, late kick detection due to low permeability formations, swabbing from the formation due to an insufficient trip margin, losses due to high equivalent circulating densities (ECD's), differential sticking, and stuck pipe following extended periods of well-control events.

It is thus of paramount importance for the operator to minimize the associated risk, time, and cost on all HPHT wells.

One such field in Pakistan where the target formation is a high-pressure shale in the Lower Basal Sand Reservoir, which is potentially a tight gas reservoir. This shale formation is known to be over-pressured, with a pore pressure of 18.6 ppg equivalent mud weight (EMW). The estimated fracture pressure of this formation is 19.2 ppg EMW, which results in a narrow drilling window. When an offset well in the field was drilled conventionally, it was plagued with severe well control issues, lost circulation, and stuck pipe events due to ineffective ECD management with a conventional mud system. The operator spent a total of 45 days to regain control of that well.

The operator for the subject well therefore intended to deploy an automated managed pressure drilling (MPD) system to drill the target section with minimal nonproductive time (NPT). The MPD system was expected to facilitate drilling the section with minimal overbalance and compensate the required bottomhole pressure (BHP) with the application of backpressure. The automated MPD system would also account for mud density variations with a high bottomhole temperature (BHT) by executing an advanced well-hydraulics model in real time. Furthermore, the MPD system would provide early kick detection and reaction to well control events.

The operator, in addition to drilling, intended to collect three whole cores while drilling with an MPD system.

Through the application of an automated MPD system, the operator was able to reduce the NPT to practically zero, and successfully achieve target depth and collect the three desired cores.

The paper discusses the planning, wellsite execution, results, and lessons learnt by the application of an automated MPD system in the subject field.
Running Sour Hydrocarbon Assets: Eni's Story of Experience
Authors: Scataglini Luciano , Decarli Luca
Published: November 2019

Eni has more than 40 years' experience on developing and managing sour hydrocarbons Projects. That has allowed to build up in Eni a specific knowhow, which is continuously improving and updating through operational activities on assets with an high concentration of H2S in the process fluids such as Karachaganak and Kashagan in Kazakhstan, COVA in Southern Italy and the more recent Zohr facilities in Egypt.

The Eni's acquired knowledge in running sour hydrocarbon assets, both offshore and onshore, has been founded on a robust risk based approach. Since the project start, risk assessments such as blowout study, Quantitative Risk Assessment, Emergency Escape Rescue Analysis, etc. results are considered the pillars for the proper design, construction, commissioning, start-up and operations phases. Specifically, SIMOPS/CONOPS methodologies and procedures and their applications in sour operational contexts are defined for managing sour hydrocarbons assets and activities.
Achievement of Maximum Mud Weights in WBM with Micromax/Barite Blend and its Successful Implementation in Deep HPHT Challenging Environment
Authors: Sindi Rami , Pino Rafael , Gadalla Ahmed , Sharma Sunil
Published: November 2019

The use of water based mud (WBM) in drilling applications under extreme Pressure and temperature has been increasing rapidly in the drilling industry over the past few years. It is now more crucial to close the technological gap that presents challenges towards developing high Density water based mud systems for High Temperature High Pressure (HPHT) wells. These challenges include rheology control, weighting agents sagging tendencies associated with high down hole temperature, In addition to the high solids loading which limits the free water availability impacting polymers performance and therefore, rheology, HPHT fluid loss and filter cake thickness control become an issue that requires special optimization and extra field maintenance. Operating under narrow margin between pore pressure and fracture initiation pressures adds to the complexity of the drilling fluids maintenance where a slight change in the bottom hole pressure (BHP) could lead to significant increase in the non-productive time "NPT" due to the time spent in solving possible fluid losses and kicks.

This paper discusses the outstanding performance achieved in a deep HPHT formation drilled using water base mud weighted with Manganese Tetroxide (Micromax)/Barite blend, from planning and extensive lab testing to field implementation. This paper also describes and compares the methodology of using Micromax/Barite versus using barite only as the weighting agent and finally the field results.
State-of-the-Art Plant Operation Combining Kaizen & Digital Technology and the Challenge for LNG Value Chain Optimization
Authors: Arai Toru , Otawara Yuki
Published: November 2019

A prosperous business player must gain a competitive advantage over other companies to survive and dominate the market. In Japan, electricity market has progressively started its liberalization in 2000, and full liberalization in 2016 allowed all consumers to freely choose the power retailer.

In response to these dramatic changes in the business environment, we have proactively introduced KAIZEN and digital technology to gain a competitive edge. KAIZEN was introduced in Japanese automobile manufacturing and based on the philosophical belief that "nothing is seen as a status quo and everything can be continuously improved by racking one's brain." Simply saying, it is an initiative to improve efficiency value-adding work, and to eliminate non-value-adding work and waste & loss which we can not recognize. In addition, the advancement of digital technology enabled us to analyze the big data which we have storaged from the past more easily and in more detail.

As a result of introducing of KAIZEN and digital technology, the periodic inspection of thermal power plants has been shortened by over 40 %, and maintenance costs have been reduced by over 30 %.

This paper illustrates the details of our initiatives implementing KAIZEN and digital technology and our challenges in optimizing the LNG value chain applying the KAIZEN knowledge.
A Game Changer for Injection Wells Outflow Control Devices to Efficiently Control the Injection Fluid Conformance
Authors: Mohd Ismail Ismarullizam , Konopczynski Michael , Moradi Mojtaba
Published: November 2019

A new autonomous outflow control device is developed to choke back the injection fluid into natural/induced fractures and mitigate the disproportional injection of fluid into the thief zone and potentially creating short-circuit to the nearby producer wells. This paper will present an overview of the flow loop performance testing, and demonstrates the design consideration and integration with completion design and its benefit by reservoir modelling.

The bi-stable devices should be installed in several compartments in the wells and operate as normal outflow control valves initially. When the injected flowrate flowing through a bi-stable valve exceeds a designed threshold, the bi-stable valve will autonomously move to another position to choke back the injection of fluid at that specific compartment. This allows the denied fluid to be distributed among the valves installed at neighbouring compartments. This performance enables the operator to minimise the impacts of natural fractures on the injected fluid conformance and to control the growth of thermal fractures while improving the efficiency of the injection well systems.

The flow performance of the bi-stable valve has been validated and the flow behaviour can be simulated in the reservoir model. Static flow modelling has been used to establish the valve setting and packer placement in the well section and to demonstrate an improved distribution of the water injection and the effect of restricting water to the thief zone on the nearby producer oil recovery.

A reservoir modelling method has been established to evaluate the bi-stable device performance in reservoir environments and compared with outflow control devices (OCDs) and open hole completions. Due to the uncertainty of heterogeneous reservoirs and the potential for dynamic changes of injection properties, the simulation study showed that with a lower pressure drop compared to OCDs, the fluid front can be managed more efficiently to achieve the desired sweep and maximised ultimate recovery.

The first autonomous injection valve that restricts water into dilated/propagated fractures is developed. This device removes most of the deficiencies of OCDs and eliminates the requirements of running PLT and the prescribed well interventions e.g. closing/opening of sliding sleeves. Instead, it provides operators with a tool that enables the optimised completion to deliver optimum water injection techniques autonomously.
Innovative Solution to Automatically Import Well Production Profile Data into Process Simulation
Authors: Hassan Eman , Loretelli Giorgio , Singh Harendra , Kamal Faris , Takeidinne Ousama
Published: November 2019

EPC Contractors face the challenge of practicing/doing various activities that in most cases include some routine work (e.g. well characterization in Process simulation that requires extensive data entry, etc.). This routine work can be minimized by using developed automised solutions. These solutions will help to perform the above tasks as well as other tasks with higher efficiency and accuracy, less time and minimal errors while the Process Engineer will focus on more valuable tasks.

The Production Profile is one of the most important documents provided in any EPC stage since it is the basis for Process activities like simulations.

As per normal practice, the Process Engineer is requested to characterize each well in HYSYS using a no. of separation stages that depends on the project requirement. Well characterization includes finding the choke valve inlet flowrate and composition at the operating conditions using the productivity data. Productivity data includes the flowrates at Stock Tank Conditions and the reservoir composition. This task requires an extensive data entry since all wells have to be characterized for various production years. Moreover, any revision of such document may require an extensive re-work.

Performing Process simulations for an upstream project can be a challenging activity due to the possibility of having a high No. of wells that may need to be characterized in HYSYS. Moreover, the well characterization in HYSYS requires the input of oil/gas/water and gas lift productivity data in dedicated adjust blocks. For example, in a project having 100 wells and 4 governing cases, the No. of data that needs to be entered is 1200. This activity needs to be performed by the Process Engineer by reading the production profile and enter its data manually in HYSYS.

NPCC has developed a new software whose scope is to:Import the Production profile in a standard templateProvide a track change for any production profile revision.Provide the governing cases (Max. Oil/Gas/Water) and their relevant production years for individual wells/Flowlines/Trunklines/Pipelines as well as the overall production.Automatically export into HYSYS the production rates that need to be used for well characterization.

With the above software, the following benefits are achieved:Reduction in manhours.Increase in efficiency.Minimum supervision from Process Engineer is required.Reduction of mistakes/human errors.

This paper demonstrates that saving in manhours/manpower is achieved by interfacing EXCEL and HYSYS through VBA. Dedicated software has been coded to import the production profile provided during FEED/EPC stage in a more presentable and organized format that can be sourced to HYSYS. This will help in facilitating process simulations as well as achieving higher efficiency in Process activities.
Integrated Reservoir Study to Maximize Oil Recovery by Optimizing Shuaiba Dump Flooding into the Kharaib Reservoir
Authors: Mahmoud Ahmed , Khayami Abdulla , Mansoor Mohamed , Buasali Mohamed
Published: November 2019

A significant number of Kharaib horizontal and deviated producers drilled over the last decade have suffered from casing leaks, with many occurring in the first two years of production due to the exposure to highly corrosive water from the overlying giant water-bearing formation known as Shuaiba formation, resulting in production losses and water dumping from Shuaiba formation into the Kharaib reservoir through these damaged wellbores. This paper investigates the impact of Shuaiba dump flooding on the Kharaib reservoir’s performance, the integrated reservoir management study that was conducted and the implementation of the study’s findings to achieve the best results.

Severe casing leaks are the main production problems facing the Kharaib reservoir. A few repairs were attempted initially, however, high costs and failure rates led to a decision to cement squeeze all remaining casing leak wells, recomplete them in shallower reservoirs, and drill new replacement wells. All new Kharaib wells were designed with an extra casing to protect against the Shuaiba reservoir’s corrosive water. Although there are no longer any casing leak wells in Kharaib, their impact remains. The pre-casing leak production numbers and well counts are yet to be matched, and there is a large volume of hydrocarbons to be produced from the Kharaib reservoir. In addition, wells that are offset of old casing leak wells showed an increase in water cut, while the performance of new wells drilled down-structure of casing leak wells suffered from early water breakthrough. There is also strong evidence that the isolation in many casing leak wells, performed during the recompletion workovers, may be unsuccessful. All these factors indicate that dump flooding is likely ongoing in the Kharaib reservoir.

The consequences of dump flooding have not all been negative. An increase in average reservoir pressure and a strengthening of the reservoir’s weak water drive mechanism were observed. Currently, many wells have shown an increase in oil production, while other wells have shown steady oil production with a very gentle decline which is particularly reflected in wells located up-structure of the casing leaks. As a result of the study, many wells have been drilled in carefully selected locations in order to take advantage of the flooding, and the results of the study concluded a sustained production with a low water cut. Moving forward, there are further opportunities to increase the recovery factor by mitigating the unwanted effects of Shuaiba dump flooding and utilizing the phenomenon to its best potential.
Maximizing Conversion of Residues to Chemicals and Clean Fuels
Authors: Biswas Goutam , Chabot Julie , Gillis Daniel
Published: November 2019

International Maritime Organization’s Marine Fuel Rule, or IMO 2020, is just around the corner. Few refineries are ready for the change to bunker fuel specifications caused by IMO 2020 where marine bunker fuel sulfur content will be reduced to 0.5 wt% from current 3.5 wt%. Many refineries around the world, who currently produce about 4 million barrels per day of high sulfur bunker fuel stocks, still need to invest in upgrading technologies.

In the past Visbreaking was used to make Residue Fuel Oil (RFO) as it reduces the viscosity of the resid by thermally cracking the heavy molecules, thereby minimzing cutter stocks. It also has a relatively low capital and operating costs compared to other residue upgrading technologies. However, it concentrates contaminants (sulfur, nitrogen, and Conradson Carbon Residue (CCR)) in the product. As a result, it is not considered a viable solution for RFO sulfur reduction.

Fortunately, there are several technologies available to upgrade the high sulfur residuum oil to high value products or low sulfur fuel oil as shown in Figure 1. The benefits and features of each of these options is discussed in this paper to provide an understanding of the various processes’ merits. Case studies are also provided to provide indications of which technologies are best suited depending on the specific scenario.
CLONNE Modeling, A Novel Core and Log Prediction Through Artificial Neural Network
Authors: C A Razak M Amin , Khalid Khaliza , Sutiyono Sigit , M Shah Jamari , Md Zainuri Md Zarin
Published: November 2019

Core & Log Neural Network Modeling (CLONNE) has been initiated to utilize an ANN to optimize usage of available data to generate synthetic logs and core data which enable user to eliminate any special logs and core data acquisition in the future. This will reduce the well cost and time required for data acquisition and data analysis.

CLONNE process starts with data gathering of the available core and log data which then QC'ed and conditioned for bad hole, light hydrocarbon, thin lamination and normalized. Then pair of core and log data are combined as dummy well to generate the first CLONNE model that can be used to predict for the whole fields. Conventional data including density, neutron, sonic, GR logs and other parameters are used to generate output. A random well from the field is selected to test the predictability matching of CLONNE versus the real data acquired. Several calibration performed to provide the best predictability.

Currently a number of CLONNE models have been created for offshore fields in Malaysia. For CLONNE Synthetic logs, 4 models have been created to predict Porosity, Bulk Density, Neutron and Shear Slowness. For CLONNE Synthetic core, 3 models have been created to predict Grain Size, Permeability and Porosity. All of this models have managed to predict quite well in both thick sand and laminated sand. More models will come to predict other log curves and core parameters. The models established has been tested in one field, where a synthetic sonic log has been created. After the drilling and subsequent logging run, an actual sonic log has been deployed and compared which yield to 96% comparable. The data predicted from CLONNE can greatly save almost 15 months spend to acquire and analyze core data and also almost RM 6 Million total expenditure to acquire and analyze core data.

In 2018, CLONNE has achieved RM 6 Million cost avoidance from application in 3 fields in Malaysia. The CLONNE model generated can be implement to Basin wide prediction thus enable the sharing use of data. This will help to integrate the data available instead of data being utilize in the specific field only.
Reservoir Inter-Well Connectivity Analysis Based on a Data Driven Method
Authors: Liu Wei , Liu Wei David , Gu Jianwei
Published: November 2019

Quantitative study of inter-well connectivity is significant for understanding which injector influence the producer, and making rational injection operations to improve water flooding efficiency. In this paper, a data driven method is presented to evaluate inter-well connectivity based on bottom-hole pressure of both injection wells and production wells.

In the development and production of fields, producers are always kept in constant production rate. Thus it is more appropriate to conduct inter-well connectivity analysis using bottom-hole pressure data rather than historical injection and production rates. However, the bottom-hole pressure data cannot directly obtained. The on-site monitored well head pressure and dynamic liquid level are first used to computation and obtain bottom-hole pressure for both injectors and producers. And then preprocessing the bottom-hole pressure using non-linear diffusion filters for capturing attenuation and time lag, and constituted the data set for machine learning. An artificial neural network (ANN) is then generated and trained to simulate connect relations between producers and its surrounding injectors. Genetic algorithm (GA) is also applied to optimize the time lag and hyper parameters of ANN, which helps to save time compared to subjective adjustments. In the last, sensitivity analysis is conducted on the well-trained ANN to quantify connectivity between injectors and producers, and detecting the connect status.

The proposed methodologies were first applied to two synthetic case, and then to real field case. The results were shown to be capable of capturing connection relations between injectors and producers, and highly consistent with known geological features, analyze results and tracer test of reservoir engineers. It indicates that the presented methods can be used to understand the flow direction of injected water, and guide to optimize water injection operation.
Treatment of Produced Water with Back Produced ASP
Authors: Al Battashi Mundhir , Al Shukaili Saada , Al Balushi Sa'ud , Al Hatmi Khalid , Al Mashrafi As'ad
Published: November 2019

Crude oil production from ageing oil fields is normally sustained by various enhanced oil recovery (EOR) ways such as water injection, polymer injection and alkaline surfactant polymer injection (ASP). One of the main ageing fields (90% water cut) in Oman is considered for this study. This field is being operated with waterflood for more than 15 years. In order to enhance the oil recovery in this field, chemical enhanced oil recovery (cEOR) using polymer flood was implemented in 2010 by Petroleum Development Oman (PDO) Company. ASP is a recovery method planned as a final resort of cEOR to recover more oil from the studied field. ASP breakthrough is expected to impact the performance of deoiling facilities in this field.

Results showed that using ceramic membrane (100 nm pore size) managed to remove oil from produced water completely for high and low OiW concentrations, however only 2% recovery factor was achieved. Using aluminum sulfate chemical as a coagulant to treat the oily produced water was only effective at concentration higher 500 mg/L. In comparison, aluminum sulfate was very effective in treating the produced water contaminated by polymer (500 ppm of polymer concentration) and at 150 mg/L of aluminum sulfate, the outlet OiW reached 39 ppm (v). When Aluminum sulfate was used at concentration of 500 mg/l, the OiW concentration reached 2 ppm (v), which is lower than the polishing unit in the water treatment system. When ASP was introduced to the produced water, the oil droplet stability has increased and at 500 mg/L of aluminum sulfate, the outlet OiW in the treated stream was around 65 ppm (v) however at 700 mg/L of aluminum sulfate, zero ppm of OiW was achieved. Introducing gas bubbles (N2) as flotation with the help of the coagulant agent had improved OiW removal efficiency by almost 15% for the PW with ASP.
A Method of Intelligent Scheme Optimization for Non-Stop System Intermittent Production Units
Authors: Wang Cai , Xiong Chunming , Shi Junfeng , Han Qiqing , Zhang Jianjun , Zhao Ruidong , Lei Gang , Zhang Xishun , Sun Yizhen
Published: November 2019

Long-time and over-frequency system power-off of normal intermittent pumping (NIP) technology may exacerbate wax deposit, hydrodynamic level instability and even system restart failure. As a consequence, non-stop-system intermittent pumping (NSSIP) have been tentatively applied into some wells of low production in the oilfield of Daqing in China. Long time pump stop will reduce well production while frequent pumping will lead to void pumping and high energy consumption. Now, NSSIP production scheme is mostly derived from experience decision, the feed and fetch of pump is unbalanced, and it is doubtful whether the low energy consumption characteristic of NSSIP really works. Thus, it is urgent to carry on the research of intelligent scheme optimization for NSSIP.

First, based on the A5 database platform of CNPC, the deliberate non-stop pumping scheme and data acquisition scheme for typical experimental wells will be formulated. Second, data of load, displacement and production rate of pumping wells by NSSIP will be measured in real time, then the pump efficiency vs dynamometer working condition will be calibrated accordingly. The CNN+SNN+HDG model is used for training, and the quantitative diagnosis model of insufficient liquid supply is established to realize the intelligent prediction of pump efficiency through dynamometer recognition. Third, the physical model of bottom hole flowing pressure buildup is established to realize the quantitative evaluation of reservoir liquid supply capacity. Data models for correlation analysis of the pumping time, dynamic liquid level, output rate, system efficiency and other parameters are established. At last, the key parameters that affect the pump balance of feed and fetch and economic benefit of a single well are screened out, and the all above analysis results and models are integrated into the ensemble decision tree model to optimize the most reasonable pumping time and frequency for NSSIP schemes.

It is suggested that fluid supply capacity affect the intermittent scheme most. For low permeability and low production well, NSSIP could sustain pump fullness, increase system efficiency and save energy at the same time. Based on the ensemble method for intelligently production scheme optimization, NSSIP could increase system efficiency by 7.8% over normal pumping, and by 4.4% over normal intermittent pumping in average. What's more, NSSIP could reduce energy consumption by 22.14 kWh per day compared with intermittent in average.

Non-stop-system intermittent pumping (NSSIP) may effectively prevent pumping system from failures caused by void pumping or long-time system stop. It could also greatly increase pumping and system efficiency and save more energy.
Using Shear Wave Anisotropy Approach to Determine State of Stress Around the Wellbore from Advanced Acoustic Well Logging; Case Study from Southern Iraq
Authors: Dahm Haider H. , Abbas Ahmed K. , Alhumairi Mohammed A. , Alsaba Mortadha , Mohammed Haider Q. , Al-Hamad Nasser
Published: November 2019

Drilling operations in deep shales are more challenging due to geomechanical problems such as wellbore instability. Neglecting the impact of geomechanical issues may lead to drilling drawbacks such as loss of circulation, wellbore collapse, tight hole while tripping, stuck logging tools, and subsequent fishing, stuck pipe, and sidetracking. The directional dependency (anisotropy) of the rock properties, especially the rock strength, cause variation in the wave velocities. Identifying orientation and degree of the anisotropy and its relationship with geomechanical problems is essential for further field development. In this paper, acoustic data from vertical and deviated wells in Zubair Formation, Southern Iraq were performed to provide insights on the state of stress distribution around the wellbore through the Zubair Formation. In addition, interpreting the flexural dispersion curves as the final result of cross-dipole data processing, the maximum stress direction has been obtained to illustrate the type and source of anisotropy around the borehole in this formation. Using the flexural dispersion curves and the shear wave splitting approaches, the direction and the degree of anisotropy were determined in Zubair formation. Results indicated that drilling operations have altered the state of stress around the wellbore, and the degree of alteration is a function of the magnitude and the direction of the anisotropy. The flexural dispersion curve shows that the upper member of Zubair Formation is strongly anisotropic, whereas a slight anisotropy was mapped within the middle member of the same formation. In addition, shear wave splitting analysis revealed that the stress changes along the direction striking from north to west. Thus, considerable attention should be paid to all 1D-geomechanicsl models that constructed for Zubair Formation given its strong aviation of the magnitude and direction of its strength and elastic properties.
Innovative Pioneer Approach for Gas Wells Testing without Flaring in Offshore Field Abu Dhabi
Authors: Ladmia Abdelhak , Al Hammadi Yousif Hasan , Al Hosani Fahad Mustfa , Ballaith Faisal Jamaan , Alshamsi Abdalla Hussain , Hussein Ahmed , Essam Ahmed
Published: November 2019

Technical difficulties to test and monitor Offshore Gas wells completed with 7" mono-bore (High rates: 100-120 MMSCFD & Barge Testing equipment are limited to a Max. rates of 45 MMSCFD or less) and the impact of shutting these wells on the gas deliver.

An innovative solution that is industrially and ecologically superior to more traditional methods of gas testing. The SONAR technology of the Clamp on SONAR Flow Surveillance provides accurate measurements of gas flow rate with no pressure drop or energy loss, a wide turn-down ratio and no need to cut the pipe or stop the flow, installation is easy and maintenance is minimal. The combination of accurate measurements and ease in installation makes the Clamp on SONAR Flow Surveillance the perfect fit for a very wide range of applications. It provides the optimum basis for solutions that are perfectly tailored to Offshore Gas wells.

Clamp on SONAR flow surveillance is particularly flexible and economical, reduce engineering time, increase plant availability and enable practice- related well production. Test at any time Gas wells & detects any change. This is critical for most Offshore Gas wells reservoir development projects.Remove Barge testing; avoid associated problems & saving Barge timeSafe, Quick & InexpensivePrevent production cut off & loss while conducting testingGood saving in term of Barge Cost and Gas Gain.

By applying the SONAR technology of the Clamp on SONAR Flow Surveillance that provides accurate measurements of gas flow rate with no pressure drop or energy loss, a wide turn-down ratio and no need to cut the pipe or stop the flow, in addition to the easy installation where the maintenance is minimal as well as to save significant cost of the Barge and gas flaring.

An example of a novel technical concept and serves as a motive for applying new technology to test High Rate Gas wells that can assure safe continuous monitoring in addition to save Barge Time & Cost and Prevent production cut off & loss.
Managing High Cost in Offshore Construction : Pan Malaysia Maintenance, Construction and Modification PM-MCM Strategic Initiative
Authors: Zakaria Irman Zubir , Engku Mahmud Engku Azam , Md Farick Farahin , Juhari Muhammad , M Johari Arina
Published: November 2019

Pan Malaysia Maintenance, Construction and Modification (PM-MCM) Contract 2018 – 2023 is a PETRONAS-led initiative in collaboration with Malaysian Oil & Gas Operators, which are also known as Petroleum Arrangement Contractors (PAC), aimed at cost optimization through the technical standardization of offshore Hook-up and Commissioning (HUC) and Topsides Major Maintenance (TMM) works. The initiative was participated by ten (10) Petroleum Arrangement Contractors (PACs) operating in Malaysia (redundant).

The initiative competitiveness relied heavily on the number participating PACs in order to accumulate and integrate sufficient volume of work through sharing of their long-term offshore work plan over a period of 5 years with active contribution on lessons learned, best practices, and challenges. Leveraging on high volume of work per region will generate the economics of scale thus drive cost reduction.

The technical standardization is achieved through the identification of minimum requirements for each work (HUC and TMM) by operators, and where applicable, common specifications are accordingly derived. This simplifies the requirements and accordingly reduces the number of specifications to be complied across the region, thus, effectively allows the HUC/TMM Contractors to competitively quote the best price for the services.

Apart from the technical standardization and optimization above, the initiative is further supplemented through the standardization of the Contract Terms and Conditions among the PACs. However, landing to an agreement amongst the ten (10) established Oil & Gas Companies was crucial and considered as a major challenge, as each company had operated differently under their own set of Terms & Conditions. Despite this, consensus achieved towards standardization.

In assisting the tender evaluation and aligning with PETRONAS’ effort towards Digitalization of its Busines Operation, digital tools were deployed. Online eAuction and digital bid price analyzer were extensively used to commercially evaluate and to identify best value for PETRONAS and PACs, respectively.

In conclusion, the PM-MCM contract was successfully awarded with a significant cost reduction against the original estimated cost by approximately 40%. In comparison to previous contracts, Pan Malaysia MCM also recorded significant reduction in most of the unit rates of similar services rendered. Market feedbacks obtained by participating bidderss indicated that the standardization had indeed helped the participants to lower their prices.

Pan Malaysia Maintenance, Construction and Modification Contract has brought forward industry players into one crucial objective of cost optimization. The collaboration between PETRONAS and PAC which resulting for greater impact and value to all players involved through productivity improvement and cost reduction.
Effect of CuO and ZnO Nanoparticles on Efficacy of Poly 4-Styrenesulfonic Acid-Co-Maleic Acid Sodium Salt for Controlling HPHT Filtration
Authors: Beg Mukarram , Kesarwani Himanshu , Sharma Shivanjali
Published: November 2019

Water based muds (WBM) provide an eco-friendly and cost effective way out for drilling a petroleum well without using oil based muds. WBM may cause some problems when a water sensitive formation (such as shale) is encountered during drilling. The infiltration of water from mud causes formation minerals to dissolve that may lead to formation damage. Fluid loss also alters the rheological properties of mud which is highly undesirable hence fluid loss should be minimum.

Present study aims to experimentally investigate the effect of CuO and ZnO nanoparticles in presence of poly(4-styrenesulfonic acid-co-maleic acid) sodium salt (PSSM) as a fluid loss control agent for WBM at high pressure-high temperature (HPHT) conditions. Base mud containing hydroxyethyl cellulose was mixed with 1.0 w/v% of PSSM and varying concentrations of either nanoparticle (0.25, 0.50, 0.75 and 1.00 w/v%). The resulting drilling fluid formulations were examined by using viscometer, high temperature ageing cell in roller oven, API filter press, HPHT filter press and capillary suction timer. Zeta potential of nanoparticles in water with and without PSSM was measured using particle size analyser. Filter cake formed by API filtration tests were analysed by field emission scanning electron microscope (FESEM). Ageing experiments were also performed at 230°F for 16 hours and HPHT filtration tests were conducted at 300°F.

Experimental studies have shown that the addition of CuO decreased the rheological parameters such as apparent viscosity, plastic viscosity and yield point by 10 to 15% before hot rolling of drilling fluid. After hot rolling, the rheological parameter for mud containing CuO were reduced, but as the concentration of nanoparticle increased, the rheological properties improved. Effect of CuO was more pronounced as compared to ZnO nanoparticles on fluid loss. The addition of 1.0 w/v% PSSM in base mud reduced LPLT fluid loss to ~64%. API fluid loss of PSSM containing mud was further reduced by ~12% on addition of only 1.0 w/v% of CuO. At 1.0 w/v% concentration of ZnO, API filtrate of base mud reduced by ~8%. HPHT filtrate loss for mud having 1.0 w/v% PSSM was 14.6 mL in 30 minutes at 300°F. Addition of nanoparticles further reduced HPHT filtration loss by 15 to 20%. FESEM images of filter cakes suggested that there were complex structures of polymer chains covering the pores of filter cake, and the network was further blocked by the nanoparticle clusters, therefore inhibiting the passage of fluid through it.

The results obtained from this experimental work have shown that the efficiency of polymer as fluid loss reducer has improved due to the addition of nanoparticles, especially with CuO. The novel combination of CuO nanoparticles with poly(4-styrenesulfonic acid-co-maleic acid) sodium salt can further be explored and engineered to develop an efficient fluid loss reducing formulation for water based mud.
A Microfluidic Study of Wettability Alteration Rate on Enhanced Oil Recovery in Oil-Wet Porous Media
Authors: Yuan Shuai , Liang Tianbo , Zhou Fujian , Liang Xingyuan , Yu Fuwei , Li Junjian
Published: November 2019

Replacing oil from small pores of tight rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, liquid nanofluid (LNF) has less adsorption loss during transport in the porous media and can efficiently alter the rock wettability; both make LNF a promising candidate to enhance oil recovery from tight reservoirs. In this study, a 2.5-D visualized micromodel with micro-sized pore throats is applied to elucidate the impacts of wettability alteration and spontaneous imbibition on oil-water flow in the porous media. Results provide direct evidence that the concentration of LNF changes wettability alteration rate and interfacial tension, and thus influencing the displacing rate of water into the originally oil-wet pores. This helps to optimize LNF usage in the fracturing fluid for enhanced oil recovery from tight rocks.
Reservoir Modeling using Thin Layer Analysis and Characterization e-tlac™ Approach for Turbiditic Environment
Authors: Gangemi Giovanni , Galli Maria Teresa , Cruciani Francesco , Barbacini Giulia , Dallorto Margherita
Published: November 2019

Thin turbidity siliciclastic reservoir is a challenging deep-water environment for modeling. In a deep off-shore field in West Africa, sedimentological characterization of these reservoir suggests typical turbiditic sandstones: Arenites with medium granulometry and normal gradation over imposed by plane-parallel sand laminations intercalated by shaly levels (late stage turbidity sandstone beds - characterization by Mutti, 1992). The oil bearing reservoir, is producing both from thick sands and thin layer sands. It is supposed the presence of up to 40% of sand-shale inter-bedded layers with a thickness less than 0.3m.

These sands are defined in the reservoir model by curves of petrophysical properties, log facies, characterization of thin bedded intervals and a volume of seismic inversion.

Tuning analysis suggest the potential seismic resolution is 16 meters. Seismic inversion was processed to generate a higher resolution driver for modelling.

Formation evaluation uses high-resolution logs within "Thin Layer Analysis and Characterization" (e-tlac™) method (Galli et Al., 2002) which helps enhancing thin inter-bedded facies characterization, not captured with conventional logs. The method provides an estimate of the Sand content, Porosity and Saturation logged by the tools with thin lithology.

High-resolution logs were acquired only in three wells over twelve drilled in the field. For this reason, a re-calibration of all conventional CPIs including the "e-tlac" output results was necessary to better control the reservoir property distribution all over the grid.

This methodology increased capability estimating pay volume close to real value avoiding underestimation of Net Sand and Water Saturation overestimation.

The solution to model thin turbiditic sands within the static 3D model is integrating all the above data inputs (stratigraphical environment, seismic inversion volume and "e-tlac" output). Reservoir cores was the input for the sedimentological study; the seismic inversion volume was background for reservoir facies distribution and "e-tlac™" formation evaluation output to assign unbiased reservoir properties to sand and thin layer facies at the well position.

As lesson learned, the acquisition of triaxial induction, high-resolution dielectric or image is the key to better characterize the inter-bedded thin levels that are present in similar deep-water environment.