इलेक्ट्रिकल और इलेक्ट्रॉनिक सिस्टम जर्नल

GUPCO is one of the major companies in Egypt using Gas Lift for operating more than 500 wells across Gulf of the Suez (GoS). To ensure that wells operate as designed for their assigned life with all risks as low as reasonably practicable, GUPCO initiated an in-house Well Integrity Management Policy (WIMP) with combination of well modeling to simulate the operating conditions. WIMP defines the operating standards for maintaining well integrity parameters, securing well potential availability and emphasizing on the problem prevention before happening. In addition, well modelling plays a vital role in such challenging mature fields that helps in decreasing Natural Flow Capability (NFC) physical test frequencies, especially for vast infrastructure.

Case A: a Shut-in well re-perforated due to formation damage and is classified as high risk according to WIMP due to NFC and communication between annulus and tubing. Based on reservoir performance, the well should stabilize at higher WC. Well modeling quantified the value to be self-killed and the plan changed from rig workover to producing the well for a month to monitor the WC with a temporary dispensation from WIMP for diagnostic. The well stabilized at higher WC and saved workover cost.Case B: a vessel collided with one of the GoS Platforms, which leads to structural failure, and physical NFC tests at zero Well Head Pressure (WHP) for the wells became impossible before toppling the P/F. Well modeling using PROSPER helped to identify wells potential, NFC of each well and choose the proper securing method.

Gas lift is one of the most common and efficient artificial lift techniques. Thereby, it has been widely recognized and successfully applied worldwide for increasing oil production. The objectives of this simulation study are to investigate effect of gas injection rate and injected gas composition on oil production to determine the optimum injection rate, effects of parameters such as water-cut, well-head pressure, and tubing roughness on oil production, reliability of used well test data, and model the field performance along with life of the reservoir. The IPM simulator is used for simulating actual production systems and assessing their responses to different production scenarios. PROSPER software is one of the most important packages of the IPM that is used to maximize the production earnings by providing critical analysis of the performance of each producing well and groups of wells. The PROSPER simulator is used to model all wells individually using actual PVT data of the deviation survey, down-hole completion, geothermal gradient, and average heat capacities. The model is constructed and matched with the real data and thereby the best fluid and well production correlations are selected. Then, the constructed model is used to determine the optimum gas injection rate for the subject well. Finally, sensitivity analysis tests are performed to simulate and investigate the effect of other parameters which are believed to have a real impact in optimized gas lift process. The investigated parameters include; injection gas composition, water-cut, well-head pressure, and tubing roughness The attained results indicated that gas lift optimization process is inevitable for obtaining high oil production rates and several variables should be considered,  optimization of gas injection rate increases the oil production, injected gas composition, water-cut, and well-head pressure have an important effect while tubing.

Well integrity is a combination of several disciplines integrated into the different phases of the well lifecycle with ultimate objective to prevent well control incidents. The subject of this paper is about effectiveness of various well integrity monitoring techniques at different stages of the field life. It is based on actual Company lessons learned and recent experience in managing well integrity incidents, when all barriers got lost. Wellhead pressure monitoring is one of the most popular methods of well integrity surveillance. It is based on the double barrier envelope concept: primary barrier envelope is the one exposed to pressure; secondary barrier envelope is the one that will be exposed to pressure if primary barrier fails. Therefore, once the primary barrier fails, it is expected to observe pressure at surface as an indication of the failure. Therefore each well operator has internal fit for purpose wellhead pressure monitoring system. Some specific well categories might be monitored more frequently than another due to higher risks associated with these wells.

Double barrier policy is a well integrity requirement well-known world-wide. This policy applies to wells with positive pressure at surface capable to flow naturally. This policy is the basement for wellhead pressure monitoring system. However, based on the latest Company’s well integrity experience, this system is applicable for green fields only, with brand new barriers installed and tested. In case of mature brown fields after several decades of production this system may not always work perfectly. It may happen that failure of the primary barrier envelope occurs in the wells with already failed secondary barrier envelope. In this case there is no any "grace" period to respond to the failure and we immediately get a well control incident reflecting in uncontrolled release of well media through failed barriers. Therefore at some point of field development the time comes when secondary barrier envelope is not reliable anymore and additional surveillance activity has to be implemented to ensure safe operating conditions in the fields. This paper warns well operators on the potential gaps in the well integrity monitoring that may lead to the severe incidents. Those gaps may not exist at the early stages of development but appears during the "transition from green to brown" field. The paper helps to recognize the period for activating additional surveillance techniques avoiding unnecessary OPEX impact. It also describes various surveillance techniques for secondary barrier envelope including leak detection, corrosion logging and pressure testing.

Poor seismic regions underneath a thick salt succession showed great challenges in subsurface description especially at offshore fields where investment budget is a challenge. Therefore, Integrated subsurface studies incorporating advanced static and dynamic reservoir modeling workflow have proved its great impact on investment decisions upon such uncertainties. Modeling intersected lobes of bars and channels, quality, and lateral and vertical connectivity are major uncertainties in heterogeneous multilayered Cretaceous Nezzazat group at Gulf of Suez. Such a heterogonous reservoir requires high-quality facies modeling to honor Gulf of Suez depositional environment for sand presence risk. This also involved petrophysical characterization of Nezzazat group into different hydraulic flow units honoring the lithostratigraphy of the basin, Mattula, Wata and Raha formations. Despite the short production history, the team set a proactive surveillance plan including several static reservoir pressures surveys, PBU tests, and Production logs. The Big Loop 3D reservoir simulation approach is applied to overcome geological, petrophysical, and reservoir engineering uncertainties.Dynamic data has been integrated with RFT data and HFUs permeability distribution scenarios in history matching.

Nezzazat Group showed high layer-by-layer permeability variations and consequently, its distribution was a key sensitivity parameter to estimate wells interference and incremental recoverable reserves for early, consolidated and economically viable development options. permeability distribution was controlled using conventional core data, PBU permeability estimation, and Nodal analysis.Observed different reservoir pressures at offset wells recorded at the same time indicated limited lateral connectivity and vertical heterogeneity; has been matched with distributed facies. Within Big Loop reservoir simulation several sensitivities have been run to cover the uncertainty range in fluid properties, aquifer strength, vertical heterogeneity, relative permeability, and absolute permeability distribution. This opened a window towards drilling more two new production wells to increase the ultimate recovery factor for the field with ± 6:7 % and one water injection well to increase the ultimate recovery factor by ± 3:4 %; with high certainty for the incremental recoverable reserves for each scenario. Therefore, the proposed methodology helps to evaluate multi-layered heterogeneous reservoirs helps to understand hydraulic flow units’ architecture for better development plans and further secondary recovery proposals.

This paper will help most of the reservoir engineers and geoscientists working on heterogeneous multilayered reservoirs with a lack of data, especially at offshore fields. Integrated approach workflow will help in weighing uncertainties considering static and dynamic data to minimize required simulation runs. It will be helpful to understand complex heterogeneous reservoirs and consequently shows how much does this impact new well delivery decisions considering location and time plan.

3D geocellular static models are the key input for fluid flow simulations with the main aim to predict the future reservoir performance for a particular recovery scheme. Since the predictability of the dynamic model depends on the quality of the geocellular model, it is imperative that the input data, the modelling workflow, methodologies and approaches are verified and validated prior to the sanction of the geocellular model. The objective of this paper is therefore to discuss the process of performing quality assurance and quality control (QA/QC) of 3D geocellular models exhibiting real field examples from the Middle East carbonate reservoirs. 3D static models are built using data from multiple sources, at different scales and with different degrees of uncertainty. The validation and reconciliation of all the data is of paramount importance. The procedure to build any geological model is very similar provided all the data is available. Some variations in the procedure are expected depending on the complexity of the phenomena to model, but must of the time workflows divert based on data quality and data availability. In this paper we discuss the use of key validation checks for each step of the modelling process taking into account the data quality and field maturity, namely for the structural framework modelling, facies modelling, porosity modelling, permeability modelling, rock type modelling,water saturation modelling, upscaling and uncertainty analysis.

The use and validation of the applicability of secondary variables in the petrophysical modelling, such as acoustic impedance from seismic inversion, is also addressed. From the analysis of multiple geocellular models, inconsistencies were detected at different stages of the modelling process, starting from the well surveying with implications to horizontal well positioning within the framework, to the modelling of facies and petrophysical properties, with inconsistencies on variogram model parameters. Also, the validation of the velocity modelling and time-depth conversion used for the structural framework was validated by comparing FWLs depths against spill points. Furthermore, the quality of the facies model could be verified against regional facies belt maps (similar variogram azimuths are expected) while the validation of the permeability scale-up at well level could be achieved by reconciling with well test kh data. These are just a few examples of the material discussed in this paper. The novelty of the quality assurance process pertained to 3D geological models is the identification of appropriate metrics with key performance indicators for each step in the modelling workflow. At the end of the QA/QC process the models are ranked in quality and technical gaps identified for subsequent model improvement. Guidelines and best practices are also presented in this paper.

Most of the current Egypt oil production comes from mature oil fields. Increasing oil recovery from these aging resources is one of the major concerns for the Egyptian oil industry in order to meet the growing energy demand in the coming years. To increase oil recovery from existing fields, operators in Egypt have started to pay more attention to heavy and extra heavy oil fields. Due to its high viscosity, different Enhanced Oil Recovery (EOR) techniques are considered and implemented appropriately. This paper will present the history and present applications of the different Enhanced Oil Recovery (EOR) techniques in Egyptian oil fields, covering the main problems

encountered in the operation of each technique including the actions taken to overcome or eliminate these problems. The current study will cover fields located in in the Eastern

and western Deserts of Egypt.

Enhanced oil recovery (EOR) processes are well known for their efficiency in incrementing oil production; however, the selection of the most suitable method to adopt for specific field applications is challenging. Hence, this chapter presents an overview of different EOR techniques currently applied in oil fields, the opportunities associated with these techniques, key technological advancements to guide the decision�making process for optimum applicability and productivity and a brief review of field applications. Oil recovery efficiency is greatly dependent on the microscopic and macroscopic displacement efficiency. Generally, microscopic displacement efficiency measures the extent to which the displacing fluid mobilises the residual oil once in contact with the oil, and it is greatly controlled by factors such as rock wettability, relative permeability, IFT and capillary pressure note that a decrease in oil viscosity, IFT or capillary pressure of the displacing fluid can increase the microscopic efficiency.

Macroscopic displacement efficiency, otherwise known as volumetric sweep efficiency, measures the extent to which the displacing fluid is in contact with the oil-bearing parts of the reservoir (metre to hectometre scale, and it is influenced by the rock matrix heterogeneities and anisotropy, displacing and displaced fluid mobility ratio and injection and production well(s) positioning. The product of microscopic (Ed) and macroscopic (EV) displacement efficiency yields the overall displacement efficiency (E) of any oil recovery displacement process.

E=EdEvE4 And Ev=EiEaE5, where Ei is the vertical sweep efficiency and Ea is the areal sweep efficiency.

Natural drive mechanisms recover oil during the initial or primary production stage of a reservoir by means of the natural energy present in the reservoir without the need of supplying any additional energy. These natural mechanisms use the pressure difference between the reservoir and the producing well bottom. The total recoverable oil using this method is considered inefficient, as recovery is usually less than 25% of the original oil-in-place. Secondary recovery techniques are applied when the natural reservoir drive is depleted ineffectively and inadequately for augmenting production. This technique involves injection of either natural gas or water to stimulate oil wells and maintain reservoir pressure in the injection wells. The injected fluids act as an artificial drive to supplement the reservoir energy. Such fluids boost the flow of hydrocarbon towards the wellhead. If the injected fluid is water, the process is usually termed waterflooding; if the injected fluid is gas, the process usually involves pressure maintenance operations.

Gas-cap expansion into oil columns (wells) displaces oil immiscibly due to volumetric sweep�out. Diverse methods are used for fluid injection into oil reservoirs to support the natural forces. Recovery efficiencies in the secondary stage vary from 10 to 40% of the original oil�in�place. Other gas processes, whose mechanisms entail oil swelling and viscosity reduction, or favourable phase behaviour, are enhanced oil recovery (EOR) processes. Tertiary recovery techniques otherwise called enhanced oil recovery (EOR) processes demonstrate enormous potential in recovering stranded oil trapped at the pore scale after primary and secondary recovery techniques by capillary pressure�driven snap�off, which leaves behind in the reservoir about one�third of OOIP. The stranded oil is often located in regions considered inaccessible. EOR methods can extract more than half of the total OOIP and significantly more than the primary and secondary recovery methods. Notably, the impact of EOR on oil production is colossal as an increase in recovery factor by only 1% can yield 70 billion barrels of conventional oil reserves globally without the exploitation of unconventional resources. In comparison to primary and secondary recovery methods, EOR undeniably is a better alternative as its contributions to global oil production entails a more economically feasible process.

Crude oil recovery takes place in three production stages primary, secondary and tertiary oil recovery processes. On average, oil recovery from the primary and secondary production stages is approximately one�third of the original oil-in-place (OOIP), while the remaining two-thirds of the oil, can be partially recovered through the application of tertiary processes also known as enhanced oil recovery (EOR) processes, which are key drivers for incremental oil recovery. EOR processes include thermal (TEOR), chemical (CEOR), gas flooding miscible and immiscible (GEOR) and microbial or MEOR processes. Thermal EOR techniques are applied for the recovery of heavy oils. In particular, steamflooding is the dominant thermal EOR technique worldwide. Increase in oil productivity is achieved through viscosity reduction, oil swelling, steamstripping and thermal cracking.

A decline in global oil and gas upstream investment which led to a fall of oil and gas price in 2015 by 25% and another fall of 26% in 2016, this global fall affected the major oil companies worldwide. Interestingly, in 2017 and 2018, there are good signals of oil price recovery resulting from rise in demand. However, the future is blink and uncertainties abound owing to increased demand for alternative and renewable energy and a rise in global demand for sustainable energy and green revolution. This paper seeks to propose strategies for Nigerian National Petroleum Corporation (NNPC), the National Oil company of Nigeria to reposition itself in other to braze up with challenges that are eminent in the future of oi and gas energy marketplace. NNPC enjoys the economics of scale, monopoly, large Nigerian population level, titanic dominance in African oil market, abundance of oil reserves and the vast resources the nation is blessed with are its strengths. Its weaknesses are evident in bad maladministration, corruption, lack of political instability and mismanagement of oil wealth. Suggested strategies for reposition NNPC to meet its challenges are making strategic investment decisions, visionary and innovative leadership are key management decisions that will keep the Nigerian National Petroleum Corporation in tune to navigate the modern-day global oil market challenges.

Nigeria is the largest oil producer in Africa. It holds the largest natural gas reserves on the continent and was the world’s fifth-largest exporter of liquefied natural gas (LNG) in 2018. Although Nigeria is the leading crude oil producer in Africa, production is affected by sporadic supply disruptions. Nigeria's crude oil and natural gas resources are the mainstay of the country's economy. Because Nigeria heavily depends on oil revenue, its economy is noticeably affected by crude oil price changes. The International Monetary Fund (IMF) projects that Nigeria’s crude oil and natural gas exports earned $55 billion in 2018, which is $23 billion higher than in 2016.The growth in export revenue, which can be partly attributed to the rebound in crude oil prices, has helped improve Nigeria’s fiscal position. However, Nigeria’s fiscal deficit remained flat at 4% of its gross domestic product (GDP) because of a significant increase in capital expenditures and lower-than-expected non-oil revenue collection, in spite of improvements to the country’s tax administration. The Nigerian government still heavily relies on crude oil and natural gas revenue; its non-oil revenue comprises only 3.4% of GDP, one of the lowest in the world.

According to the Oil & Gas Journal, Nigeria had an estimated 37.0 billion barrels of proved crude oil reserves by the end of 2019—the second-largest amount in Africa after Libya.The majority of reserves are along the country's Niger River Delta and offshore in the Bight of Benin, the Gulf of Guinea, and the Bight of Bonny. As a member of the Organization of the Petroleum Exporting Countries (OPEC), Nigeria renewed its commitment to reduce crude oil production in April 2020, capping its production at 1.41 million barrels per day (b/d). The agreement takes effect on May 1, 2020, and ends on April 30, 2022. However, Nigeria’s compliance with the OPEC+ agreement has been intermittent; the country has at times produced more than the agreed-upon quota in the past. In addition, Nigeria has designated some of its crude oil streams as lease condensate, which is not subject to the OPEC+ agreement production cuts, which allows Nigeria to circumvent its obligation to reduce production. In 2019, Nigeria produced about 2.0 million b/d of petroleum and other liquids, of which 1.65 million b/d was crude oil. The remainder is composed of natural gas plant liquids, other liquids, and refinery processing gains.

The deepwater Egina project was the latest significant field to come online in Nigeria. The Egina field came online in January 2019 and reached its peak production plateau of 200,000 b/d at the end of 2019. The Nigerian minister of petroleum, Emmanuel Kachikwu, has labeled Egina crude oil as a condensate, in spite of its API gravity and sulfur content being specified at 27° and 0.17%, respectively, a crude oil assay that would place it in the medium, sweet categories. Smaller fields, such as the offshore Gbetiokun field and the onshore Qua Ibo field in the eastern part of the Niger Delta, have provided marginal increases to Nigeria’s crude oil production in the past year. These projects have helped to partially offset production declines at Nigeria’s older, more mature fields. Other planned deepwater projects have been repeatedly delayed because of regulatory uncertainty surrounding the PIB. In addition, the recent deepwater royalty tax increase may further inhibit investor interest in exploration and development of new offshore fields. Exploration activities have largely focused in deepwater and ultra-deepwater offshore fields, partially as a result of security concerns onshore, and many IOCs have divested their onshore assets. The NNPC plans to launch a new crude oil licensing round in mid2020, although the licensing round will likely be postponed until after the PIB legislation issue is resolved later this year. Whether or not there will be sufficient investor interest if the PIB does not pass is unclear, given the recent amendments to the royalty tax structure for deepwater production.

Government support and investor interest in solar power projects have been growing in the past few years in Nigeria, partially as a way to mitigate natural gas supply shortages and to increase access to electricity in remote and rural areas. The Nigerian government, the Rural Electrification Agency, and the World Bank-funded Nigeria Electrification Project are jointly funding a $75 million grant to encourage off-grid solar investments to reduce kerosene and diesel use for lighting and backup power generation. In July 2016, Nigeria signed power purchase agreements with 14 utilityscale solar photovoltaic facilities that have a total generation capacity of 1.1 GW, although none of these projects has yet reached financial close, and reportedly the independent power producers and the Nigerian government have a dispute regarding tariff pricing.

The exploration and exploitation of hydrocarbons forces the oil companies to improve the drilling process, therefore every aspect of this operation that has the opportunity for optimization should be researched. In 2016, Mohamed El Neiri proposed a hybrid drilling technique where the zone located around the bit remains in underbalanced conditions and the rest of the drill string is overbalanced, such conditions requires some modifications in the design of the drill bit. The aim of this project was to modify the nozzle angle of a PDC drill bit in a CAD design tool and to simulate the dynamic behavior of the drilling fluid across the bit, with and without the modifications, with a software tool using CFD techniques to determinate by comparison of the fluid properties, the impact of them.

The simulation consists in three stages: pre-processing, solver and post-processing. During the first phase the adaptation of the geometry, generation of the grid and the insertion of the physical models which characterize properly the system are done. Subsequently, the settings of the solver are set, such as the type of special discretization to finally, in the post-processing validate the results obtained by observation of the response variables profiles. In this study, were used service packs of the commercially software ANSYS®.

For each one of the proposed geometries a differential pressure and velocity analysis were done and this information provided fluid data in some scenarios: when the drilling fluid enters to the nozzle, flows through it and exit as well as it strikes the formation. The results may represent and advance for the sake of the postulates of the hybrid technique. Polycrystalline diamond compact (PDC) drill bit design influences the bit hydraulics and hence the drilling performance. To improve the hydraulics, the fluid flow pattern across the drill bit should be optimized for low pressure drop, low recirculation flow and high velocity. Design of Experiments (DOE) was used to study the effect of various design parameters. Computational Fluid Dynamics (CFD) was used to simulate the fluid flow in the complex geometry of the drill bit. Response Surface Methodology was applied to optimize the design parameters for improved bit hydraulics.

Preliminary simulations were conducted by increasing the complexity to meet the realtime operation. Simulations based on fractional factorial experiment were used to identify the significant factors from the 15 design parameters. The optimum limits of the most significant five factors were identified from simulations based on central composite design (CCD). The optimization procedure was assessed by comparing the optimum design with the original design for Newtonian and Non-Newtonian conditions.

One of the most important concerns in the oil and gas industry is the time and cost associated with drilling wells. The focus of the drilling industry is to minimize the overall drilling cost without compromising the safety and environmental standards. The efficiency of drilling, measured in terms of the Rate of Penetration (ROP), is the most important criteria in the drilling economics as it directly influences the time taken for drilling a well. Based on the relationship between drilling cost and ROP, it had been shown that maximizing the ROP will result in minimizing the drilling cost. The rate of penetration or the drilling performance depends on the lithological characteristics of the formations being drilled, drilling fluid properties, the downward force acting on the drill bit or Weight on Bit (WOB), rotation of the drill bit (RPM) or the combined rotation of drill string and the downhole motor (DHM), and bit hydraulics. Among the above parameters, drill bit hydraulics has been recognized as the major factor influencing the drilling performance.

The purpose of proper hydraulic design of drill bits is to have appropriate conditions of drilling fluid flow rate and bit pressure drop to facilitate the removal of cuttings generated during drilling. Bit hydraulics plays an important role in this process, especially during drilling in sticky or soft formations such as shale plays. Poor hydraulic design causes improper bottomhole cleaning, which may result in balling (the accumulation of cuttings on the bit face) that decreases the ROP, or may halt drilling in severe cases. Drill bit design influences the bit hydraulics in terms of the drilling fluid flow rate and pressure drop across the bit which affects the removal of generated drill cuttings; bottomhole cleaning; reduced chip hold-down pressure and bit cooling as well as power consumption. Some typical problems due to ineffective bit hydraulics are bit balling and pre-mature bit wear due to regrinding of chips. These problems will reflect on the drilling performance and hence increase the drilling cost. Increasing the hydraulic power at the mud pump improved the drilling performance of jet bits.

Drilling operations have a significant effect in oil and gas exploration and production due to its economic reason. Less drilling time can directly lower the overall cost of exploration and production in oil and gas. This project focuses on the hydrodynamics study of a Polycrystalline Diamond Compact (PDC) drill bit design particularly on nozzle inclination and how it affects the bit hydraulics characteristics of the drilling fluid in the bore hole and around the PDC bit.

Optimizing the hydraulics while drilling is well-known and acknowledged to have significant effect on the overall drilling performance, where good hydraulics provide essential job of removing of drill cuttings to avoid unnecessary mechanical energy loss due to re-work on the produced drill cuttings, cooling of the diamond cutters to prolong the bit life and reduce the potential of bit balling. These factors assist in achieving high ROPs which in turn reduces drilling time thus effectively lowering the cost of a drilling operation. Different types of drilling fluids are also considered in this study as it is also known to have an effect on the drilling hydraulics characteristics. Drilling fluid systems have been continuously modified to aid in bit and drilling performance as well as functioning to maintain the well integrity with its role to provide hydrostatic pressure in the well to prevent collapsing of the well. The main objective of the study is to develop a CFD model in ANSYS Fluent for investigating PDC bit hydrodynamics. Other objectives include investigating the effects of nozzle inclination angle on the drilling fluid flow characteristics around the PDC bit and how different types of drilling fluid influences the PDC bit hydraulics. Drilling simulations models are created using the computer software ANSYS Fluent. Simulations are run using realizable k-epsilon model to correctly simulate the turbulence effect undergone by the fluids around the PDC bit during drilling operations. Several simulations are run with different nozzle inclination angle and types of drilling fluid which have been proven to have significant effect on the flow characteristicaround the PDC bit.

A mathematical model developed for laboratory methane gas production from hydrates by depressurization method is presented. This model, solved through numerical analysis and programmed in programming language, becomes in a software tool whose results are compared to previously published laboratory tests. The proposed mathematical model is based on mass balance equations where liquid and gas are considered as mobile phases and the hydrate as an immobile phase. It is also assumed that there are not dramatic changes in temperature, so energy balance is overlooked. The proposed equations were discretized in cells by the method of finite differences and solved through Newton-Rhapson numerical method. Constitutive equations were also used to gas/water flow or production, gas hydrate dissociation and permeability changes due to the above-mentioned phenomenon.

Numerical solution was programmed in m language from MATLAB, and a graphical user interface was designed to generate a software. Simulation results were compared with two previously published laboratory tests to validate the mathematical model proposed. The data analyzed was the cumulative production of gas against time, obtaining differences under the 7% between the calculated and the reported results in the two cases. In addition, the developed software also gives dissociated gas/water volumes, saturation changes and permeability changes in the rock.

The novelty of this research is in the report of the changes in the saturations of the three phases due to hydrate dissociation in the rock, which can be supportive to a better gas reserves calculation of these structures non-produced commercially yet.

Recently methane hydrates have attracted attention due to their large quantity on the earth and their potential as a new resource of energy. This paper describes a one-dimensional mathematical model and numerical simulation of methane hydrate dissociation in hydrate reserves by both depressurization and thermal stimulation using a one-dimensional radial flow system (axisymmetric reservoir). A moving front that separates the hydrate reserve into two zones is included in this model. A numerical coordinate transformation method was used to solve the moving boundary problem. The partial differential equations were discretized into ordinary differential equations using the method of lines. Our simulations showed that the moving front location and the gas flow rate production are strong functions of the well pressure and reservoir temperature. The impermeable boundary condition at the reservoir results in very low temperature at the moving front and the formation of ice. The formation of ice, which plugs the pore volume for the gas to flow, should be avoided. Compared with a stationary water phase model, our simulations showed that the assumption of a stationary water phase overpredicts the location of the moving front and the dissociation temperature at the moving front and underpredicts the gas flow rate. The thermal stimulation using constant temperature at the well method using a single well was found to have a limited effect on gas production compared to gas production due to depressurization.

Gas hydrate production is still in the test phase. It is only now that numerical models are being developed to describe data and production scenarios. Laboratory experiments are carried out to test the rationale of the conceptual models and deliver input data. Major experimental challenges include (I) the simulation of a natural three-phase system of sand–hydrate–liquid with known and high hydrate saturations and (II) the simulation of transport behavior as deduced from field data. The large-scale reservoir simulator (LARS; 210 L sample) at the GFZ has met these challenges and allowed for the first simulation of the gas production test from permafrost hydrates at the Mallik drill site (Canada) via multistage depressurization. At the starting position, hydrate saturation was as high as 90%, formed from dissolved methane only. Whereas gas hydrate dissociation determined the flow patterns in the early pressure stages, the importance of different transport behaviors increased at lower pressure stages and increasing water content. Gas flow patterns as observed in Mallik were recorded. While the conceptual model for the experimental data does agree with the model proposed for Mallik at moderate and low gas production, it is different at high gas production rates.

In the medium term, gas hydrate reservoirs in the subsea sediment are intended as deposits for carbon dioxide (CO2) from fossil fuel consumption. This idea is supported by the thermodynamics of CO2 and methane (CH4) hydrates and the fact that CO2 hydrates are more stable than CH4 hydrates in a certain P-T range. The potential of producing methane by depressurization and/or by injecting CO2 is numerically studied in the frame of the SUGAR project. Simulations are performed with the commercial code STARS from CMG and the newly developed code HyReS (hydrate reservoir simulator) especially designed for hydrate processing in the subsea sediment. HyReS is a nonisothermal multiphase Darcy flow model combined with thermodynamics and rate kinetics suitable for gas hydrate calculations. Two scenarios are considered: the depressurization of an area 1,000 m in diameter and a one/two-well scenario with CO2 injection. Realistic rates for injection and production are estimated, and limitations of these processes are discussed.

Gas hydrates are ice-like solid compounds of water and gas molecules (clathrates) which are stable at low temperature and elevated pressure. The water molecules build out cages by hydrogen bonds in which gas molecules are embedded. Generally, gas hydrates can contain different guest molecules in different cages, depending on their sizes and the availability of guest molecules under given thermodynamic conditions, but methane is the prevalent gas in natural gas hydrates. The exploitation of natural gas hydrate deposits that are known in various permafrost regions and submarine sediments all over the world is in the focus of several research groups because the amount of methane to be recovered could overcome future energy shortages. The greenhouse gas CO2 is able to build hydrates too, and these hydrates are thermodynamically more stable than methane hydrates. The possibility to destabilize methane hydrate by injecting CO2 as pressurized gas or in liquid form was verified in several small-scale experiments carried out by different research groups. Thus, the combination of both processes offers the opportunity to open up new energy resources as well as to combat climate change by reducing CO2 emissions. However, the technical realization of this combination of processes has to face various challenges. Besides the technical and economic efforts for drilling in submarine sediments or in deep layers in permafrost regions, these challenges concern the reaction kinetics and transport resistances within the sediments in which methane hydrates are embedded in natural deposits.

Thus, to find the best strategy for methane recovery from a specific deposit with or without CO2 sequestration, a large variety of parameters describing the properties of the particular layer as well as the time- and location-dependent thermodynamic conditions have to be considered. Within the framework of the German SUGAR (SUbmarine GAs Hydrate Reservoirs) project, strategies to produce natural gas from marine methane hydrates and simultaneously store CO2 as hydrates are explored. Before undertaking drilling tests, numerical simulations of the local processes are necessary and helpful. For this purpose, a new scientific simulation model called UMSICHT HyReS was developed to describe the methane production from submarine hydrate layers and the exchange of methane by carbon dioxide. In addition, the commercially available simulation tool STARS (CMG Ltd., Canada) was used. In the following, the new simulation tool is described, and the results of the calculations based on particular reservoir parameters, reaction kinetics, and extraction techniques are outlined.