bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparative Analysis of Gas Hydrate Inhibitors: Local and Conventional
Authors: Elechi Virtue Urunwo , Ikiensikimama Sunday Sunday , Ajienka Joseph Atubokiki , Akaranta Onyewuchi Emmanuel , Onyekonwu Mike Obi , Okon Okon Efiong
Published: November 2019

This paper takes a look at the performance of a Locally Sourced Material (LSM) in a laboratory mini flow loop of ½ -inch internal diameter, made from 316 stainless steel pipe sheathed in a 4-inch PVC pipe built on an external metal frame work. The performance of the LSM was measured with that of the conventional hydrate inhibitor 2-(Dimethylamino)ethylmethacrylate (2-DMAEM). The performance evaluation was based on Pressure versus time, change in pressure versus time and initial and final pressure versus time plots. These plots showed that LSM performed better than the conventional 2-DMAEM in all the weight percentages considered (0.01wt% −0.03wt %). The optimum weight percentage for inhibition was 0.02wt% with inhibition efficiency of 81.58% while that of 2-DMAEM was 73.68%. The inhibition efficiency for 0.01wt% and 0.03wt% of LSM wereboth 72.81% whereas that of 2-DMAEM were 51.75% and 76.32% respectively. The LSM is locally sourced, readily available in commercial quantity and also eco-friendly because it is plant based unlike the 2-DMAEM which is toxic and expensive. It is advised that the LSM be developed as an alternative to the conventional inhibitor for gas hydrate inhibition.
Protecting Assets, Protecting People: Exploring IoT Solutions to Drive Improved Asset Integrity and HSE Performance in Oil & Gas
Authors: Ventulett Thomas P. , Villegas Leigh M.
Published: November 2019

Under budget constraints, oil and gas organizations are turning to technology solutions to ensure greater asset integrity and improve operational safety. Purpose-built digital equipment, like mobile devices and IoT sensors that are certified intrinsically safe for hazardous environments, can do both.

Communication of precise/timely information in hazardous environments allows teams to make the best decisions possible, ensuring personnel follow safety procedures and processes meet regulatory requirements, while also driving improved performance. Accurate, real-time communication in combustible environments is only possible with intrinsically safe (IS) communications hardware, such as tablets and IoT sensors. These bring industrial applications directly into ATEX/IECEx Zone 1 hazardous areas to capture/share real-time information, making them more efficient, productive, and safe.

Performing inspection activities onsite with digital devices or IoT sensors reporting 24/7 helps organizations create live and dynamic workflows in real-time. Thus, maintenance, repairs, or further assessments can be optimally scheduled. Further, digital records validate compliance (i.e. location, date, time, pictures) while driving efficiency. Pervasive digital connectivity is expected to result in savings and improved asset integrity, securing healthier and safer operating environments.

We explore the potential benefits to asset integrity and HSE management from intrinsically safe technologies that help oil and gas teams communicate better. We look at use cases where personnel collect, share, and analyze IoT data in Zone 1 operations (industrial areas where ignitable concentrations of flammable gases, vapors or liquids are likely to exist under normal operating conditions), using devices that are certified to not ignite combustible environments. When such IS solutions are applied broadly across a hazardous area operation over a period of time, we expect them to help save time, improve accuracy, and monitor personnel's well-being so they can do their jobs better and more safely - and drive better results for their organizations.

The paper describes just some of the ways that IS-certified technologies have the potential for changing how oil and gas teams communicate, helping them drive better results through improved health, safety, compliance and efficiency. We suggest testing methodologies with IoT devices for organizations to establish their own HSE baselines that can be used for benchmarking improvements from the implementation of those devices. We also make predictions for future oil and gas operations based on ongoing development of IoT/machine learning technologies and call for further research and testing in realistic scenarios.
Geology Driven History Match of Eastern Siberian Halite Cemented Fluvial Reservoir
Authors: Ibragimov Ruslan , Ovchinnikov Aleksandr , Burdakov Dmitriy , Romantsov Aleksey , Sterlyagova Svetlana , Darmaev Bator , Zimin Sergey
Published: November 2019

History matching is a crucial step in process of gaining reliable model, which further will be used for production profile forecasting, well planning, choosing proper development plan of a field. Target reservoir for which it needed to construct and history match a model included several features that made this process quite challenging:

– high lithological heterogeneity due to alluvial genesis of rocks, – large influence of diagenetic alteration of sediments on reservoir quality, – impossibility of direct using of 3D seismic data because of low thickness of reservoir formation.

This work was successfully performed through complex application of following methods:

– building detailed facial maps based on conceptual depositional model, core and wireline log data from enormous number of wells, – using both well test and production data during adjustment of model for matching.

Concerning a key peculiarity of the reservoir – salt cementing – unique method of its modeling in both static and dynamic models was applied. This model also has the feature of changing salinization coefficient of reservoir during waterflooding. The basis for applying of salt cementing of reservoir is relationship found between wireline log and salinization coefficient from core data.
Assessing Structural Uncertainty Ranges in Static Models by Incorporating Structural Control Points from Horizontal Wells: A Case Study of a Middle East Carbonate Reservoir
Authors: Contreras Perez David Rafael , Al Zaabi Ruqaya Abdulla , Viratno Bernato , Sellar Christopher , Susanto Maria Indriaty
Published: November 2019

The rationale of structural uncertainty analysis in reservoir modeling is to quantify the range of probable Gross Rock Volume (GRV) s and searchfor the means to reduce this range as much as possible. This task considers running different scenarios and/or structural configurations based on the observed mismatch between structural depth estimation from seismic mapping and stratigraphic tops derived from well data. Integrated multi-disciplinary teams can collaboratively eliminate reservoir uncertainties at the well location, however uncertainty remains in the interwell area.

The challenge for any reservoir characterization team is to share expertise across disciplines in order to mitigate the lack of information with scientific reasoning. In this way the range of uncertainties impacting business decisions, development scenarios or data acquisition plans are minimised.

The workflow summarized here is an example of how to utilize structural elements from existing wells to quantify intrinsic GRV uncertainty while building static models. Offshore Field developments usually have a bigger horizontal well count than the ideal vertical penetrations and this case study is no exception in this case study. The ultimate goal of this publication is to generate the inputs required for a more realistic set of structural realizations that fulfil all of the current understanding from horizontal well placement and their intrinsic structural uncertainty.
HSE Closed Loop Drilling for Well Integrity
Authors: Abraham Jobin , Saleh Mujahed , Hadj-Moussa Ayoub
Published: November 2019

Offset wells in this region for the past 20 years were used as water disposal wells, having 40,000 bpd water production. Past decade observed remarkable decline in production leading to the development of the current well as a replacement while abandoning the previous well. The well was ranked as medium critical considered from its long water disposal period as no integrity test were performed due to the well location. The lithology of anhydrite alternation with limestone, dolomite and thin shale layers caused a risk of losses and differential sticking. In addition, this was a H2S bearing (100 - 119ppm) salt-water flow formation.

With a rotating control head in place with the flow line valve closed providing a closed loop system, the return is dumped to the sea through the extended diverter lines, ensuring that the H2S emissions are diverted away from the rig floor and from the manned complexes.

Total losses and sour water flow made closed loop flow drilling an engineering solution for its ability to ensure no H2S migration to the rig floor and continuity of the drilling operation with returns diverted away from the rig at all times. The introduction of side entry flow line on the rotating control device (RCD) allowed utilization of an additional fill up line planned to bullhead back to the formation preventing excessive gas migration.

Extensive planning of rig interface with rotating control head with side inlet connection from the standpipe manifold to manage time and space constraints in addition to losses management providing well continuity.

The well drilled successfully with a rotating control device- RCD at surface and returns diverted safely. The closed system with rotating control device - RCD and a well head pressure monitoring gauge provided an additional security of analyzing well conditions, though risk of having gas influx was initially identified as a medium hazard being a top hole section with a higher chances of losses while drilling.

As circulation and conditioning was done traces of gas and H2S were observed with an increase in pressure observed at the RCD. Bullheading from the side inlet of the RCD from standpipe was utilized to balance the well eliminating the risk of high exposure of H2S gas at surface. Having the only pressure monitoring system in place with the RCD the overhead pressure could be identified to raise the mud weight and to balance the well. This operation was successful and resulted in zero gas at surface with casing and cementing operations on the well conducted safely without any quality, health or safety issues.

Understanding the risk of less information about the formation led to the approach of utilizing a low pressure rotating head system to drill safely into a H2S risk zone. This paper identifies how a previously used system, could have an innovated approach to drill safely in a total loss and H2S prone formations.
Rotating Equipment Switchover Dashboard
Authors: Alzahrani Khalid , Alzahrany Abdulaziz
Published: November 2019

CONTENT

This Instruction outlines the procedures for testing spare pumps. The text includes: DefinitionResponsibilitySwitching IntervalsSwitching TimeSwitching ProcedureSwitchover Dashboard

DEFINITION

This procedure outlines switching between "Main Pump" (running pump) and "spare pump" (the one to be tested). All other type of equipment's (rotating and/or stationary) will be switchover based in the following:PM (Preventive Maintenance) program.Inspection ProgramTest and Inspection T&I program

STRATEGY OBJECTIVES

RESPONSIBILITY

Operation Superintendent:

Area Operation Foreman:

Reliability Engineer:

SWITCHING INTERVAL

Switching between spare pumps and main ones shall be done once every 4 to 6 weeks to ensure the equipment availability and reliability. It shall coincide with the monthly vibration survey. For the compressor lube oil system, the functional test is preferred to be scheduled before a planned compressor shutdown.

Discussions were held with the rotating equipment manufacturers, specialists and users to clarify all corrosion, electrical and mechanical concerns regarding the switching periods between alternate pieces of rotating equipment. The compilation of all of these discussions and concerns resulted in the following two basic guidelines which within themselves comprise the heart of the Rotating Equipment Operating Strategy.

A. MEDIUM VOLTAGE EQUIPMENT (Higher than 600 V up to 13.8 KV):

Equipment of this voltage type should be switched from the stand-by mode to the operational mode once per month.

Note: Excluding any stand-by equipment that is not required by Operations should be run a minimum of one continuous hour every month.

B. LOW VOLTAGE EQUIPMENT (Equal or Less than 600 V):

Equipment of this voltage type should be switched from the stand-by mode to the operational mode once every two weeks. This includes the switching between the main and auxiliary lube/seal oil pumps.

Note: Excluding any stand-by equipment that is not required by Operations should be run a minimum of thirty continuous minutes every two weeks.

SWITCHING Time

Switching between critical pumps shall be conducted during the normal working days in day time where the support organizations are available.

SWITCHING PROCEDURES

This RIM covers four different pump startup scenarios. Each one of these scenarios includes important checks and procedures that need to be followed to ensure a reliable pump start-up. Below you will find a detailed start-up procedure for each scenario. The procedure will be detailed but general, additional steps may be required for some particular process.

FOLLOW UP PROGRAM

Key Performance indicators (KPI's)

Switchover = (Total Equipment comply with switchover/Equipment Schedule Switchover) X 100%, Target 90%

Note:

Switchover the pump:

START-UP AND STOPPAGE FOR DEFERENT TYPE OF ROTATING EQUIMPMENT
First Retrievable Application of Lower Completion Stimulation Technology
Authors: Almaawali Sultan , Kumar Kamlesh , Awang Zaini , Duvenhage Viljoen
Published: November 2019

New operational application using a field-tested stimulation technology that was previously only available as a permanent installation as part of the lower completion was recently successfully applied as a retrievable option. This alternative installation method reduces rig time, overall project cost and returns the wellbore to Open Hole should it be required for post stimulation logging or future interventions. The lower completion stimulation technology consists of standard liner pipe that is made up offline to short Subs and the sub-assemblies are then preloaded with four tubes up to 40 feet in length, each tube with a jetting nozzle on the end. The liner string with casing packer was run into the open-hole well section with Subs positioned across the formation where stimulation was required. 15% HCl acid was then pumped at the designed rate that resulted in the penetration of the tubes into formation. Post stimulation the complete liner assembly was then retrieved by releasing packer with straight pull and shearing tubes that has entered the formation (the penetrated needles remain inside the formation). Many operational challenges were overcome by the PDO's drilling team in order to complete this first of its kind installation utilizing multiple running string combinations and a small work over rig (Max 125 kdan) in order to keep the overall project cost down.
Evaluation of Probability Point Estimate Methods for Uncertainty Analysis of Hydrocarbon in Place as an Alternative Techniques to Monte Carlo Simulation
Authors: Algdamsi Hossein , Amtereg Ahmed , Agnia Ammar , Alusta Jamal , Alkouh Ahmed
Published: November 2019

Typically, the Monte Carlo simulation (MCS) approach was generally applied to assess and quantify uncertainty in probabilistic reserve estimates and improve risk decision making, regrdless of that it can be quite computationally intensive, MCS method has the advantages of generating possible outcomes That contain more information relative to deterministic and scenario approach by taking into consideration the uncertainty associated with the range of various input variable. However, MCS entails that the probability distribution functions of all uncertain input parameter be entirely known, this might be an obstacle or limitation on successful implementation of MCS as subjectivity on the selection and definition of the input variable distributions and their characterization or due to incomplete information and lack of data will critically impact and limit both its proper application and interpretation of the results and consequently doubt statistically the robustness of the solution. This shortcoming of MCS and difficulty can be circumvented by other complementary method like the PEM, first-order second moment (FOSM) or Warren’s probability analysis methods which does not require a previous knowledge of the range and distribution shape to be defined or condition where information concerning uncertain parameter is not sufficient or reliable, moreover it has the advantage of less computational requirement to attain solution with comparable accuracy. This paper provides a comparative assessment of Point Estimate Method (PEM) for analyzing uncertainty of hydrocarbon in place as more practical alternative approaches to Monte Carlo simulation (MCS). Five PEM Rosenblueth, Harr, Che-Hao et al., Geethanjali et al. and Hong 2n scheme algorithm were used to model output uncertainty of hydrocarbon in Place for more than 20 field and predict P10, P50 and P90 using different PEM Technique. MSC result was generated for the same fields with an optimum number of samples for key variable using stability analysis and statistical measure of model run convergence which are benchmark to which the PEMs’ results are compared.
Deep Learning and Hybrid Approaches Applied to Production Forecasting
Authors: Shoeibi Omrani Pejman , Vecchia Adrian Luciano , Dobrovolschi Iulian , Van Baalen Thijs , Poort Jonah , Octaviano Ryvo , Binn-Tahir Huzaifah , Muñoz Esteban
Published: November 2019

Reliable forecasting of production rates from mature hydrocarbon fields is crucial both in optimizing their operation (via short-term forecasts) and in making reliable reserves estimations (via long-term forecasts). Several approaches may be employed for production forecasting from the industry standard decline curve analysis, to new technologies such as machine learning. The goal of this study is to assess the potential of utilizing deep learning and hybrid modelling approaches for production rate forecasting.

Several methods were developed and assessed for both short-term and long-term forecasts, such as: first-principle physics-based approaches, decline curve analysis, deep learning models and hybrid models (which combine first-principle and deep learning models). These methods were tested on data from a variety of gas assets for different forecasting horizons, ranging from 6 weeks to several years. The results suggest that each model can be beneficial for production forecasting, depending on the complexity of the production behavior, the forecasting horizon and the availability and accuracy of the data used. The performances of both hybrid and physical models were dependent on the quality of the calibration (history matching) of the models employed. Deep learning models were found to be more accurate in capturing the dynamic effects observed during production – this was especially true for mature fields with frequent shut-ins and interventions. For long-term production forecasting, in some cases, the hybrid model produced a greater accuracy due to its consideration of the long-term reservoir depletion process provided by the incorporated material balance model.
Real-Time Structural Risk Assessment for Offshore Asset Management
Authors: Atia Mohamed , Keys Matt , Omar Tarek
Published: November 2019

Middle East offshore platforms installations started in the early 60's and continue today. Managing asset integrity and demonstrating compliance is increasingly challenging due to frequent brownfield modifications, increased safety factors with the introduction of international standards, changes in metocean data and age deterioration. From work with North Sea, Gulf Region and Asia Pacific operators, an approach was developed to manage ageing assets using real-time structural risk assessments and operational procedures that ensures consistent risk levels of life safety and environmental for all assets and is applicable to all regions.

Utilising the improved accuracy of modern weather forecasts, in combination with structural reliability, a methodology has been developed to determine the forecasted risk level for any critical element. This is updated live, with each new weather forecast, to provide proactive notifications and alerts so operators have more up to date knowledge to make decisions on their assets. A live web-based system can be utilised to display this information.

The approach splits the three risks of life safety, environmental and structural damage into separate requirements and calculates the probability of failure, which will lead to each of the three consequences, for the critical component or the overall structure. The risk is evaluated and compared with the industry standard and the operators own acceptance criteria to determine if operational procedures need to be enacted to reduce the consequence. It has been found that the acceptable risk levels for the ‘in a forecasted storm’ risk are governing over the traditional design ‘annual’ risk levels.

If at any point in time the probability of a wave height approaching the field exceeds the maximum allowable for a structure, the system issues timely alerts and warnings to the relevant stakeholder for their actions. The operator then has the option of de-manning or shutting down operations to maintain the risk levels for life safety and environmental at ALARP (as low as reasonably practicable) levels. The system also provides information for post-storm structural damage likelihood.

A combination of online monitoring, inspection and/or asset loading history, which can be incorporated using Bayesian updating methods, and advanced assessment have been used to reduce the occurrence of enacting operational procedures for structures that are non-code compliant to greater than every 10 years while also reducing the annual risks.

An additional advanced feature can be utilised by connecting installed accelerometers to the structure for continuous live streaming of the structural response which can issue alerts if any damage is suspected.
Miscible N2 EOR in a Giant High Temperature Complex Carbonate Reservoir
Authors: Xu Siqing , Mogensen Kristian , Al Shehhi Budoor , Mabrook Maged , A. BinAmro Ahmed , E. Ali Ahmed
Published: November 2019

In this paper, we investigate the potential for applying miscible nitrogen injection as an enhanced oil recovery (EOR) method for a high-temperature, low-permeability carbonate reservoir, which contains a volatile oil with some H2S and CO2. The field, which is located onshore Abu Dhabi, is still in its early development phases but suffers from relatively low throughput rate because of low permeability. Various gas injection schemes are being considered, with different source gases. At the prevailing reservoir pressures, extensive phase behavior studies confirm that the reservoir fluids develop miscibility with nitrogen, carbon dioxide, and hydrocarbon gas.

The simulation studies involve a number of sensitivity runs performed on sector models, which are sufficiently fine-gridded to capture the compositional transition zone propagating between injector and producer pairs. Miscible nitrogen injection comes out as a viable option with the potential to increase recovery by 10 to 20% above the current water flood development scheme. The significantly improved sweep and displacement efficiency are due to N2 miscibility with reservoir oil under reservoir conditions, possibility of increased PV injected in a N2 WAG scheme, and the ability to maintain a higher reservoir pressure (at initial reservoir pressure).

From a surface facilities point of view, techniques for N2 capturing is mature, tried and tested. N2 being inert does not pose corrosion risks to well completion and surface facilities. However, capital costs for N2 rejection units – if utilised in a N2 WAG EOR scheme – will need to be taken into account. Although N2 WAG EOR is seen to be very attractive for the reservoir under study, alternative EOR schemes are also being actively evaluated. The aim is to arrive at an optimum EOR project for the reservoir in line the achieving the 70% oil recovery aspiration.
Combined Solution for Lost Circulation Treatment to Successfully Drill Through Naturally Fractured Vugular Porosity Formation on ERD Wells in the UAE
Authors: Bermudez Romulo , Abdelkerim Doutoum Mahamat Habib , Al Azizi B. , Nour Mahmoud , Medina Ruben , Bereikaa Hesham , Rocha M. C. , Nasrallah M. M.
Published: November 2019

While drilling through the initial section of extended reach drill (ERD) wells in Abu Dhabi where the trajectory requires a high inclination across a recognized loss zone various options were required to be assessed to maximize efficiency while balancing risks. Factors such as loss rate, capability of mixing fluid, necessary density to help prevent flow from a shallow water-bearing zone, and rig time, where all necessary and key factors to consider in the design process.

For this UAE field with common losses in the surface casing, brine capping was determined the best solution to continue drilling without generating nonproductive time or creating a possible wellbore instability issue when unable to keep up with building mud to offset mud losses. For wells with a higher inclination angle, when the loss rate reached the point where it was not possible to prepare the fluid to keep up with losses, it was necessary to identify a different solution to cure or significantly reduce the losses and enable the hole section to be drilled without potential operational risks.

For vugular/fractured porosity formations, using tailored particle size materials was unsuccessful for curing the losses. Therefore, a unique solution was implemented by combining two different systems to battle the losses: a swelling polymer lost-circulation material (LCM) that hydrates and helps reduce flow velocity into the formation, followed by a shear-rate rheology-dependent cement system that is a tunable and tailored slurry with thixotropic properties, which stops losses and develops low compressive strength. With this combined solution, the drilling process was successfully resumed and completed.

The usual loss rate for this particular vugular argillaceous limestone formation is between 600 and 800 bbl/hr while drilling. Once the solution was successfully implemented, losses were reduced to 15 bbl/hr. The technique was performed on a second well, applying the lessons learned from the first attempt, and the unique solution achieved a dramatic reduction of losses to 2 to 6 bbl/hr. The cost and effectiveness of the treatment demonstrated that this solution is best for optimizing the drilling process for this particular condition.

Applying a swelling polymer LCM and the shear-rate rheology-dependent cement system cured losses for an argillaceous limestone formation with fractured/vugular porosity. It is the first global application of this combined solution.
Energy Savings of Amine Sweetening Process Through Rich Solvent Recycle Approach and Low Stripper Operating Pressure
Authors: Al Hatmi Khalid , Al Mashrafi As'ad , Al Balushi Sa'ud , Al Battashi Mundhir
Published: November 2019

The amine sweetening process is one of the most matured technology that deals with acid gas removal. However, energy consumption is considered as a prominent concern for amine absorption process due to the significant energy requirement for amine re-boiler. In previous paper (SPE-192731-MS), we discussed the effectiveness of two promising debottlenecking approaches for amine sweetening process namely; lean vapor compression (LVC) and rich vapor compression (RVC). This paper objective is to study the effectiveness of Rich Solvent Recycle (RSR) and low stripper operating pressure on pre-combustion amine absorption process.

The study used ProMax 4.0 simulator, which has been well proven to have a high accurate prediction for amine sweetening processes calculations. For RSR approach, the rich solvent leaving the bottom of absorber has been divided into two streams in which one is recycled back to the bottom of the absorber and other stream continues to the same normal path as for conventional amine process configuration. The flow ratio between recycled stream to the forward stream has been optimized to provide the minimum overall duty. For the stripper operating pressure approach, the impact of lowering the pressure on re-boiler duty has been studied for two different plants. For all scenarios, the treated gas acid gas concentration and system operating window were kept as constant. The proposed approaches have been simulated in two existing two amine-sweetening plants currently under operation by Petroleum Development Oman (PDO) for H2S capture (i.e. Plant-A) and the other one for CO2 capture (i.e. Plant-B). .

The results indicate that rich solvent recycle (RSR) debottlenecking approach potentially could result in lower re-boiler duty by maximizing the solvent/acid gas contact at the bottom of the contactor with a potential energy saving of 20% for Plant-A. The ratio between recycled streams to the forward stream has been manipulated to achieve optimum energy consumption. For stripper operating pressure, it has been found that the re-boiler duty decreased due to lower operating pressure.

The study has focused on pre-combustion amine absorption process unlike most of the published studies, which focused on post-combustion processes. In addition, in this paper live plants data were used to examine the simultaneous impact of different parameters.
Study on the Correlation Between the Hydrate Formation-Blockage Risk and Gas-Liquid Flow Pattern in Horizontal Pipelines
Authors: Liu Wenyuan , Hu Jinqiu , Sun Fengrui , Sun Zheng , Li Xiangfang
Published: November 2019

Hydrate formation and blockage in pipelines are serious problems in the oil-gas production and transportation. The current research is limited to the prediction of pipeline hydrate formation. However, the small hydrate generation often does not form obvious pipeline flow-barriers. Therefore, compared with hydrate formation, hydrate growth rate and deposition rate is equally important for the emergence of flow barriers. Based on the hydrate formation-growth-deposition mechanism and combined with the hydrate experiment in the flowloop, the characteristics of hydrate formation-growth-deposition in pipelines under different gas-liquid flow patterns was studied. The results show: Different flow patterns show different hydrate formation and deposition characteristics due to different phase distribution and interface distribution. The bubble flow, cluster flow and slug flow have some similarities in flow patterns. It can be seen that the gas phase in the flow system exists in the form of bubbles, and the occurrence of thin liquid film on the tube wall under these three flow patterns is relatively rare; accordingly, the similarity of laminar flow, wave flow and annular-mist flow shows that thin liquid film or gas-liquid-pipe wall three-phase interface will always appear in the flow process, which will make the hydrate formation and deposition risk of the latter three flow patterns significantly greater than the former three flow patterns. Comprehensive analysis shows that the hydrate risk of each flow pattern is in the order of annular-mist flow > laminar flow and wave flow > slug flow > cluster flow and bubble flow. The annular-mist flow is the most dangerous flow pattern for hydrate formation and blockage, which is quite common in the oil and gas industry. In this case, special attention should be paid to hydrate prevention and control.

It is hoped that the research in this paper can provide some theoretical guidance for field construction and related researchers.
A Novel Approach in Handling Water Breakthrough in Fractured Carbonate Reservoir Through Dynamically Integrated Fracture Characterization: A Case Study
Authors: Farias Rodriguez Leopoldo , Funk Erich
Published: November 2019

A key management guideline for water-driven, naturally fractured reservoirs (NFR) is to minimize water production. Water breakthrough is undesirable as it reduces oil production rate and lowers oil recovery. Managing these reservoirs involves delaying water breakthrough and mitigating its effects. This paper describes a cross-disciplinary workflow, which serves such purposes by making use of downhole pressure gauges (DHG) pressure data-based well models along with a dynamically validated fracture model.

The data-based well model is developed from our DHG pressure-production database. It has been field tested for forecasting water breakthrough, predicting water level in wells and planning for counteractive actions. The data-based well model is combined with a detailed fracture model whose elements were derived from the systemic integration of fracture types, genetic context and interaction with the carbonate host rock during diagenesis. The resulting workflow enables the well and reservoir management team (WRM) to put the well back in production after water-breakthrough in a way that maximizes oil re-saturation from tributary fractures into the main conductive features connected to the wellbore.

A field case illustrating the application of this workflow is discussed. The outcome of the application of this workflow is compared with the performance of other wells in which water breakthrough was dealt with by merely reducing their liquid rates till water cut became manageable. A complete set of relevant measured data, including downhole pressure gauge and a post breakthrough production logging tool (PLT), is discussed in the paper. Well performance puts in evidence that the workflow discussed in this paper allows for higher oil production rates and significantly lower water production rates following water breakthrough compared against more traditional approaches for handling wells after water breakthrough.

The workflow was developed through frequent iterations between near-wellbore flow performance data-based modeling and multi-scale fracture characterization, aimed to address the impact of the main conductive features and tributary fractures on well productivity. It is of interest to anyone involved in managing NFR, especially those engaged in preserving the sustainability of the oil potential of the well (both duration and rate).
Acid-Fracturing Techniques as a Good Alternative to Help Improve Field Development Assets
Authors: Petriz Munguia Jose Maria , Gonzalez Valtierra Blanca Estela , Trujillo Hernandez Javier , Santos Sarai , Campos Monroy Katya
Published: November 2019

Acidizing and acid fracturing techniques are routinely used in two important formations in the marine regions of Mexico, the Jurassic and Cretaceous formations. These formations are naturally fractured carbonate and dolomite reservoirs having a permeability in the range of 0.19 to 22 mD, porosity from 2.8 to 6%, approximate bottomhole temperature (BHT) up to 177°C, pressure (BHP) of 10,374 psi, and a crude of 45° API. Using acid fracturing techniques helps improve the development of these assets. This paper shows the results of more than 40 acid fracturing operations performed in recent years.

Depending on the productivity evaluation, wells belonging to these assets are stimulated as part of the completion stage. Because of their low permeability, a common approach is to perform an acid fracturing operation. As a first evaluation, a minifrac test is executed to obtain the necessary data to calibrate the acid fracturing simulation model. After this step is performed, the acid fracturing design is evaluated. Generally, a sustained production acidizing technique is used for conductivity enhancement and closed-fracture acidizing is also included as a tailored treatment with an all seawater-based acidizing system.

For these operations, an average five-fold increase in oil production has been observed after treatment. In some cases wells in the completion stage, having no production before treatment, delivered up to 7000 BOPD after treatment. In these low-permeability assets, the post-fracturing response shows good results in general terms, increasing final conductivity in the near-wellbore area, and improving the production in these wells. The fracture gradient observed varies from 0.715 to 0.981 psi/ft with an average minimum stress of 13,670 psi. To perform the acid fracturing treatments, an average of 6400 hydraulic horsepower (HHP) must be available, with up to 13,400-psi surface pressure observed. As such, a stimulation vessel is necessary in all operations, applying a 26-bbl/min average pumping rate.

Globally, acid fracturing treatments are a common stimulation technique. This study shows that stimulating proper candidates in Mexico using acid fracturing significantly helps increase production, which may be relevant for the exploitation of new areas where fracturing has not been implemented.
Case Study: Enhance Fracture Complexity And SRV For Strong Heterogenous Shale Reservoir In Weiyuan Gas-field, SW China
Authors: Zeng Lingxiang , Liu Zhuang , Zheng Yunchuan
Published: November 2019

The major challenges of shale reservoir development in Weiyuan gasfield are: (1)strong geologic heterogeneity, such as geo-stress, horizontal lamination, limited complexity and propagation of hydraulic fracture; (2)casing deformation, which caused the reservoir fractured insufficiently for many engineering problems. To avoid the problem above and increase complexity and SRV of hydraulic fracture, a deeply fracturing technology (DFT) was proposed, which was validated available and had been applied in 20s wells.

Based on ununiform distribution of geo-stress, the mechanism of DFT is using temporary plugging materials to fracture the reservoir sufficiently, which can be classified in 3 major patterns, include Intrasegment/Multi-segments/Closely spaced fracturing. Firstly, according to reservoir and stimulation objectives, choosing the appropriated development pattern. Then, considering geological and engineering factors, the optimization of temporary plugging materials and pumping parameters are needed in making pumping schedule. Finally, conducting fracturing by the schedule, and combined with operation curve and micro-seismic data, choosing proper time to release temporary agents.

With the application in the field, some conclusions are as follows:(1) Intra-segment development pattern was preferred in single-segment sufficient simulation; multi-segment was favored in the development of multi-stages without bridge plug situation, especially in the stimulation of casing deformation intervals. Which also improved operational timeliness; Closely spaced perforation pattern was benefit for the segment with big geo-stress difference and the well with small well spacing.(2) DFT was validated available by fracturing curve and micro-seismic monitoring. Event response points coverage rate of segment was 100%, SRV per segment and micro-seismic events were increase by 11%-45% and 54%-429%, respectively.(3) A combination of temporary plugging ball and powder was recommended, and the optimal agents pumping rate was 3m3/min. With the treatment above, pumping pressure was increased after agents released, the peak increment is 10 MPa, plugging effect was clear.

DFT is suitable for high heterogenous horizontal interval development, and also can be combined with bridge plug to achieve segment sufficient fracturing. The most important is, it is available in casing deformation interval stimulation, which is so serious in Weiyuan gas-field.
Scoping Model Study of Carbon Capture and Storage for Enhanced Oil Recovery for the Zarrarah Oil Field in UAE
Authors: Mheibesh Yazan Ghassan , Fraim Michael , Sultan Abdullah S , Al Shehri Fahad Hassan
Published: November 2019

The purpose of this scoping model study of Zarrarah field, with ~14 BSTB, and ~30 TSCF OIIP and GIIP respectively, was to show that natural gas cap could be used in a zero emission power plant to generate electricity, produce NGLs, and capture carbon dioxide gas. Over the lifetime of the project, the injected CO2 gas will displace the oil column in the heterogeneous carbonate rock system in a miscible gravity dominate mode.

Petrophysical data needed to construct a simulation model for Zarrarh field was collected from literature review. We used 12 analogous rock types from neighboring fields of Asab and Bu Hasa. The CMG-GEM reservoir model used 18 components to describe the fluid properties and to verify no asphaltene drop out near the producing well bore. The model was calibrated on total field oil production and gas oil ratio and then various CO2 flooding scenarios were tested to optimize recovery and minimize gas coning in the horizontal well flooding patterns.

The current production method for Zarrarah field is gas cap expansion with recycling of lean methane gas into the gas cap for pressure maintenance and recovery of NGLs. The averaged over the heterogeneous rock type regions, the miscible CO2 flood recovered at least 20% additional oil for each reservoir sector. The percentage of produced NGLs from the total in place will increase from 23% to 36% over the lifetime of the project with CO2 extraction. This production method will also supply for UAE and KSA at least 20 GW of zero emissions electric power for the next thirty years. CO2 reduces the oil viscosity and reduces gas coning by swelling the oil in the natural fractures system. The optimal CO2 injection technique is flank injection starting at the northern end of Zarrarah field. At the end of project life, the CO2 gas reserves should approach 30 TSCF to flood other reservoirs in the Empty Quarter such as Shah oil field.

The novelty of this work is designing the first economic and zero emission power plant for EOR in KSA and UAE. Generating the first economic man-made CO2 storage reservoir for future miscible oil recovery in the Empty Quarter. The increased NGL recovery will help supply the feed stock for the petrochemical industry for the next 30 years. This technique has also the ability of providing a fresh water source for low salinity water flooding or local inhabitants.
Thermoelastic Fracturing on Water Injectors as Part of Injectivity Enhancement in Giant Offshore Carbonate Field. Case Study
Authors: Sarsekov Arlen
Published: November 2019

Water Injection is part of secondary recovery mechanism which aims to increase oil recovery by increasing or maintaining the reservoir pressure and provide additional pressure support.

Most of the time water injection is controlled under matrix injection below the fracture pressure in order to avoid the creation of fractures and risk of bypass oil. However, there are two different mechanisms of fracture creation in water injection: poroelastic fracturing and thermoelastic fracturing. First one will activate above fracture point, while the second one creates below the original fracture point and most of the time missed in reservoir field development

Normally fractures can be categorized in 3 groups: –Fractures induced due to increase of injection pressure above pore pressure. (Poroelastic fractures)–Fractures induced due to drilling activities (Overbalance drilling)–Fractures induced due to injection of cold water.

Fractures which are induced due to difference in temperature between injected fluid and rock fluid called thermoelastic fractures. Thermoelastic fracturing is controlled primarily by the difference in temperature between reservoir rocks and injected fluids. This paper will focus on thermoelastic fractures and its propogation along the formation.

The analysis performed in a giant offshore carbonate field in Middle East on a well level as well as field level through injection modules.

This paper will describe the mechanisms of thermoelastic fracturing and methodology to identify this type of fractures in water injectors through several cases studies.
Water Flooding Performance Prediction in Layered Reservoir Using Big Data and Artificial Intelligence Algorithms
Authors: Chen Cunliang , Yang Ming , Han Xiaodong , Zhang Jianbo
Published: November 2019

Managing oil production from reservoirs to maximize the future economic return of the asset is an important issue in petroleum engineering. One of the most important problems is the prediction of water flooding performance. Traditional strategies have been widely used with a long run time and too much information to solve this problem. Therefore, it is urgent to form a fast intelligent prediction method, especially with the development of large data processing and artificial intelligence methods.

This paper proposed a new method to predict water flooding performance using big data and artificial intelligence algorithms. The method regards layered reservoir as a vertical superposition of a series of single layer reservoirs. An injection-production analysis model is established in each single layer reservoir respectively. And then a superposition model is established only by production data and logging tools data. Finally, the least square principle and the particle swarm optimization algorithm are used to optimize the model and predict water flooding performance.

This method has been tested for different synthetic reservoir case studies. The results are in good agreement in comparison with the numerical simulation results. The average relative error is 4.59%, but the calculation time is only 1/10 of that of numerical simulation by using artificial intelligence method. It showed that this technique has capability to predict water flooding performance. These examples showed that the use of artificial intelligence method not only greatly shortens the working time, but also has a higher accuracy.

By this paper, it is possible to predict the water flooding performance easily and accurately in reservoirs. It has an important role in the field development, increasing or decreasing investment, drilling new wells and future injection schedule.
PDO Integrated Journey Management System IJMS
Authors: Hadzic Demir , Al Balushi Anwar
Published: November 2019

IJMS is PDO in-house developed solution made to support and enhance road safety in land transport operations. With more than 300 million kilometers driven per year in PDO, in harsh environment, driving is still the highest potential injury risk. IJMS has directly influenced the enhancement of road safety in PDO O&G operations. It became a role model for other O&G companies in Oman. The system enabled achieving 97% of drivers' compliance since its launch in January 2016. It supported PDO efforts in managing the risk in land transport, and to optimize its and contractors drivers' performance and behavior.

In the first chapter, the main theory and definitions were presented including road safety initiatives and best practice globally and in O&G industry that are related to IJMS.

Second chapter describes the system modules and their purposes. IJMS is modular system with integrated modules, which enables further development and enhancement of IJMS.

In the third chapter, main data and results achieved by using IJMS are presented and discussed. In addition, further actions for managing IJMS results are presented in this part.

Finally, the conclusion includes discussion about benefits and further plans of the system development.