scholarly journals Dual hydrocarbon–geothermal energy exploitation: potential synergy between the production of natural gas and warm water from the subsurface

2019 ◽  
Vol 98 ◽  
Author(s):  
Jeroen van der Molen ◽  
Elisabeth Peters ◽  
Farid Jedari-Eyvazi ◽  
Serge F. van Gessel
Keyword(s):  
Natural Gas ◽  
Financial Risk ◽  
Net Present Value ◽  
Gas Production ◽  
Added Value ◽  
Reservoir Properties ◽  
Gas Field ◽  
Gas Recovery ◽  
Water Breakthrough ◽  
High Standards

Abstract The decline of domestic natural gas production, increasing dependency on gas imports and lagging development of renewable energy production may pose serious challenges to the current high standards of secure energy supply in the Netherlands. This paper examines synergy between hydrocarbon- and geothermal exploitation as a means to reinforce energy security. The Roden gas field is used as an example to demonstrate potential delay of water breakthrough in the gas well and a resulting increase of recovered gas (up to 19%), by positioning of a geothermal doublet in the water leg of the gas field. The reservoir simulations show that the total increase of gas production primarily depends on the amount of aquifer support. An optimal configuration of gas- and geothermal wells is key to maximise gas recovery and strongly depends on the distribution of reservoir properties. The study also reveals that this option can still be beneficial for gas fields in a late stage of production. Net Present Value calculations show that the added value from the geothermal doublet on total gas production could lead to an early repayment of initial investments in the geothermal project, thereby reducing the overall financial risk. If no subsidies are taken into account, the additional profits can also be used to finance the geothermal project up to break-even level within 15 years. However, this comes with a cost as the additional profits from improved gas recovery are significantly reduced.

scholarly journals Reduced methane recovery at high pressure due to methane trapping in shale nanopores

2020 ◽  
Vol 1 (1) ◽  
Author(s):  
Chelsea W. Neil ◽  
Mohamed Mehana ◽  
Rex P. Hjelm ◽  
Marilyn E. Hawley ◽  
Erik B. Watkins ◽  
...  
Keyword(s):  
High Pressure ◽  
Natural Gas ◽  
Marcellus Shale ◽  
Management Strategies ◽  
The United States ◽  
Gas Production ◽  
Methane Recovery ◽  
Gas Field ◽  
Gas Recovery ◽  
Hydrocarbon Gas

Abstract By 2050, shale gas production is expected to exceed three-quarters of total US natural gas production. However, current unconventional hydrocarbon gas recovery rates are only around 20%. Maximizing production of this natural resource thus necessitates improved understanding of the fundamental mechanisms underlying hydrocarbon retention within the nanoporous shale matrix. In this study, we integrated molecular simulation with high-pressure small-angle neutron scattering (SANS), an experimental technique uniquely capable of characterizing methane behavior in situ within shale nanopores at elevated pressures. Samples were created using Marcellus shale, a gas-generative formation comprising the largest natural gas field in the United States. Our results demonstrate that, contrary to the conventional wisdom that elevated drawdown pressure increases methane recovery, a higher peak pressure led to the trapping of dense, liquid-like methane in sub-2 nm radius nanopores, which comprise more than 90% of the measured nanopore volume, due to irreversible deformation of the kerogen matrix. These findings have critical implications for pressure management strategies to maximize hydrocarbon recovery, as well as broad implications for fluid behavior under confinement.

scholarly journals Multiphysics coupling study of near-wellbore and reservoir models in ultra-deep natural gas reservoirs

2022 ◽  
Author(s):  
Pengda Cheng ◽  
Weijun Shen ◽  
Qingyan Xu ◽  
Xiaobing Lu ◽  
Chao Qian ◽  
...  
Keyword(s):  
Natural Gas ◽  
Pore Pressure ◽  
Production Rate ◽  
Gas Production ◽  
Permeability Evolution ◽  
Gas Reservoirs ◽  
Reservoir Properties ◽  
Gas Field ◽  
Natural Gas Reservoirs ◽  
Stress Dependent

AbstractUnderstanding the changes of the near-wellbore pore pressure associated with the reservoir depletion is greatly significant for the development of ultra-deep natural gas reservoirs. However, there is still a great challenge for the fluid flow and geomechanics in the reservoir depletion. In this study, a fully coupled model was developed to simulate the near-wellbore and reservoir physics caused by pore pressure in ultra-deep natural gas reservoirs. The stress-dependent porosity and permeability models as well as geomechanics deformation induced by pore pressure were considered in this model, and the COMSOL Multiphysics was used to implement and solve the problem. The numerical model was validated by the reservoir depletion from Dabei gas field in China, and the effects of reservoir properties and production parameters on gas production, near-wellbore pore pressure and permeability evolution were discussed. The results show that the gas production rate increases nonlinearly with the increase in porosity, permeability and Young’s modulus. The lower reservoir porosity will result in the greater near-wellbore pore pressure and the larger rock deformation. The permeability changes have little effect on geomechanics deformation while it affects greatly the gas production rate in the reservoir depletion. With the increase in the gas production rate, the near-wellbore pore pressure and permeability decrease rapidly and tend to balance with time. The reservoir rocks with higher deformation capacity will cause the greater near-wellbore pore pressure.

Modeling Condensate Banking Mitigation by Enhanced Gas Recovery Methods

2021 ◽  
Author(s):  
Adel Mohsin ◽  
Abdul Salam Abd ◽  
Ahmad Abushaikha
Keyword(s):  
Natural Gas ◽  
Finite Difference ◽  
Positive Impact ◽  
Enhanced Recovery ◽  
Gas Production ◽  
Dew Point ◽  
Productivity Index ◽  
Base Case ◽  
Enhanced Gas Recovery ◽  
Gas Recovery

Abstract Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.

DEEPWATER GAS FIELD PRODUCTION FROM SUBSEA WELLS INTO COMPRESSED NATURAL GAS CARRIERS THROUGH A HYBRID RISER TOWER

2005 ◽  
Vol 45 (1) ◽  
pp. 45
Author(s):  
J-F. Saint-Marcoux ◽  
C. White ◽  
G.O. Hovde
Keyword(s):  
Natural Gas ◽  
Eddy Currents ◽  
Gas Production ◽  
Lessons Learned ◽  
Concept Design ◽  
Vertical Load ◽  
Gas Field ◽  
Compressed Natural Gas ◽  
Field Development ◽  
Field Production

This paper addresses the feasibility of developing an ultra-deepwater gas field by producing directly from subsea wells into Compressed Natural Gas (CNG) Carrier ships. Production interruptions will be avoided as two Gas Production Storage Shuttle (GPSS) vessels storing CNG switch out roles between producing/storing via one of two Submerged Turret Production (STP) buoys and transport CNG to a remote offloading buoy. This paper considers the challenges associated with a CNG solution for an ultra-deepwater field development and the specific issues related to the risers. A Hybrid Riser Tower (HRT) concept design incorporating the lessons learned from the Girassol experience allows minimisation of the vertical load on the STP buoys. The production switchover system from one GPSS to the other is located at the top of the HRT. High-pressure flexible flowlines with buoyancy connect the flow path at the top of HRT to both STP buoys. System fabrication and installation issues, as well as specific met ocean conditions of the GOM, such as eddy currents, have been addressed. The HRT concept can be also used for tiebacks to floating LNG plants.

Enhanced gas recovery, CO2 storage and implications from the CO2CRC Otway Project

2011 ◽  
Vol 51 (2) ◽  
pp. 684
Author(s):  
Peter Cook ◽  
Yildiray Cinar ◽  
Guy Allinson ◽  
Charles Jenkins ◽  
Sandeep Sharma ◽  
...  
Keyword(s):  
Pore Space ◽  
Co2 Storage ◽  
Co2 Concentration ◽  
Gas Production ◽  
Anthropogenic Sources ◽  
Future Price ◽  
Gas Field ◽  
Enhanced Gas Recovery ◽  
Gas Recovery ◽  
Gas Fields

Successful completion of the first stage of the CO2CRC Otway Project demonstrated safe and effective CO2 storage in the Naylor depleted gas field and confirmed our ability to model and monitor subsurface behaviour of CO2. It also provided information of potential relevance to CO2 enhanced gas recovery (EGR) and to opportunities for CO2 storage in depleted gas fields. Given the high CO2 concentration of many gas fields in the region, it is important to consider opportunities for integrating gas production, CO2 storage in depleted gas fields, and CO2-EGR optimisation within a production schedule. The use of CO2-EGR may provide benefits through the recovery of additional gas resources and a financial offset to the cost of geological storage of CO2 from gas processing or other anthropogenic sources, given a future price on carbon. Globally, proven conventional gas reserves are 185 trillion m3 (BP Statistical Review, 2009). Using these figures and Otway results, a replacement efficiency of 60 % (% of pore space available for CO2 storage following gas production) indicates a global potential storage capacity—in already depleted plus reserves—of approximately 750 Gigatonnes of CO2. While much of this may not be accessible for technical or economic reasons, it is equivalent to more than 60 years of total global stationary emissions. This suggests that not only gas—as a lower carbon fuel—but also depleted gas fields, have a major role to play in decreasing CO2 emissions worldwide.

Research Progress of CO2 Sequestration with Enhanced Gas Recovery

2013 ◽  
Vol 807-809 ◽  
pp. 1075-1079
Author(s):  
Yi Zhang ◽  
Shu Yang Liu ◽  
Yong Chen Song ◽  
Wei Wei Jian ◽  
Duo Li ◽  
...  
Keyword(s):  
Experimental Data ◽  
Natural Gas ◽  
Large Scale ◽  
Economic Feasibility ◽  
Research Progress ◽  
Pilot Projects ◽  
Gas Field ◽  
Enhanced Gas Recovery ◽  
Gas Recovery ◽  
Feasibility Research

CO2Sequestration with Enhanced Gas Recovery (CSEGR) is one of the efficient and attractive scenarios to reduce CO2emission and accelerate gas field to produce more natural gas simultaneously. We review the correlational experiments, simulations and economic feasibility research about technical and economic problems of CSEGR. And the potential of natural gas increase production and CO2emission reduction in China by CSEGR is calculated. The pilot projects and simulation results show that CSEGR is technically feasible when suitable injection strategies and field management are implemented. However, economic feasibility is available only via policies of carbon credit, allowance and trade. Accurate experimental data would ensure the authenticity of key simulation parameters and reliability of simulations, but the existed experimental data is scarce. More experimental researches should be conducted to obtain a great quantity of accurate data which can make the simulation more close to the actual situation. Accordingly, the pilot projects and large-scale applications of CSEGR could be implemented successfully.

Well Completion for Effective Deliquification of Natural Gas Wells

2011 ◽  
Vol 134 (1) ◽  
Author(s):  
John Yilin Wang
Keyword(s):  
Natural Gas ◽  
Operating Cost ◽  
Gas Production ◽  
Gas Wells ◽  
Liquid Loading ◽  
Gas Recovery ◽  
Well Completion ◽  
Reservoir Permeability ◽  
Gas Fields ◽  
Gas Lift

Liquid loading has been a problem in natural gas wells for several decades. With gas fields becoming mature and gas production rates dropping below the critical rate, deliquification becomes more and more critical for continuous productivity and profitability of gas wells. Current methods for solving liquid loading in the wellbore include plunger lift, velocity string, surfactant, foam, well cycling, pumps, compression, swabbing, and gas lift. All these methods are to optimize the lifting of liquid up to surface, which increases the operating cost, onshore, and offshore. However, the near-wellbore liquid loading is critical but not well understood. Through numerical reservoir simulation studies, effect of liquid loading on gas productivity and recovery has been quantified in two aspects: backup pressure and near-wellbore liquid blocking by considering variable reservoir permeability, reservoir pressure, formation thickness, liquid production rate, and geology. Based on the new knowledge, we have developed well completion methods for effective deliquifications. These lead to better field operations and increased ultimate gas recovery.

scholarly journals Effects of the rate of natural gas production on the recovery factor during carbon dioxide injection at the initial gas-water contact

2021 ◽  
Vol 1 (3(57)) ◽  
pp. 6-11
Author(s):  
Serhii Matkivskyi
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Gas Production ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Formation Water ◽  
Hydrocarbon Gases ◽  
Water Contact ◽  
Natural Gas Production ◽  
Gas Recovery

The object of research is gas condensate reservoirs, which is being developed under the conditions of the manifestation of the water drive of development and the negative effect of formation water on the process of natural gas production. The results of the performed theoretical and experimental studies show that a promising direction for increasing hydrocarbon recovery from fields at the final stage of development is the displacement of natural gas to producing wells by injection non-hydrocarbon gases into productive reservoirs. The final gas recovery factor according to the results of laboratory studies in the case of injection of non-hydrocarbon gases into productive reservoirs depends on the type of displacing agent and the level heterogeneity of reservoir. With the purpose update the existing technologies for the development of fields in conditions of the showing of water drive, the technology of injection carbon dioxide into productive reservoirs at the boundary of the gas-water contact was studied using a digital three-dimensional model of a gas condensate deposit. The study was carried out for various values of the rate of natural gas production. The production well rate for calculations is taken at the level of 30, 40, 50, 60, 70, 80 thousand m3/day. Based on the data obtained, it has been established that an increase in the rate of natural gas production has a positive effect on the development of a productive reservoir and leads to an increase in the gas recovery factor. Based on the results of statistical processing of the calculated data, the optimal value of the rate of natural gas production was determined when carbon dioxide is injected into the productive reservoir at the boundary of the gas-water contact is 55.93 thousand m3/day. The final gas recovery factor for the optimal natural gas production rate is 64.99 %. The results of the studies carried out indicate the technological efficiency of injecting carbon dioxide into productive reservoirs at the boundary of the gas-water contact in order to slow down the movement of formation water into productive reservoirs and increase the final gas recovery factor.

scholarly journals Current state of the gas industry of the republic of kazakhstan

2021 ◽  
pp. 201-208
Author(s):  
Z. A. Imangozhina
Keyword(s):  
Natural Gas ◽  
Moving Average ◽  
Gas Production ◽  
Gas Pipelines ◽  
Gas Field ◽  
Gas Industry ◽  
The World ◽  
The Republic ◽  
Pass Through ◽  
Sphere Of Influence

The Republic of Kazakhstan possesses large reserves of natural resources. Gas is one of the most demanded energy resources in the world today. Kazakhstan is one of the 30 leading countries in terms of gas reserves and production, while constantly increasing its production potential and expanding its sphere of influence in the gas field in the world. In percentage terms, Kazakhstan owns 1.7% of the world's proven natural gas reserves. This article analyzes the indicators of the country's gas industry development. There was prepared a forecast of natural gas production up to 2030, it was made using the Brown model of moving average (CC model). The analysis of indicators of gas transportation through pipelines, such as transit and export, is made. The location on the map plays an important role in the development of the gas industry in Kazakhstan, as gas pipelines connecting Europe and Asia pass through its territory. Transit gas pipelines are used both for gas supplies to the domestic market of the country and for gas exports. The total length of high, medium and low pressure gas pipelines in Kazakhstan is 28,628 km. In addition to positive indicators indicating the stable development of the industry, the factors hindering the development of the gas industry of the Republic of Kazakhstan are identified.

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