scholarly journals Analysis of the influence of joint direction on production optimization in enhanced geothermal systems

2021 ◽  
Author(s):  
Dorcas S. Eyinla
Keyword(s):  
Pore Pressure ◽  
Production Rate ◽  
Shear Failure ◽  
Fluid Pressure ◽  
Production Optimization ◽  
Stress Change ◽  
Geothermal Reservoir ◽  
Injection Well ◽  
Joint Models ◽  
Joint Orientation

AbstractHeat extraction from geothermal reservoir by circulating cold water into a hot rock requires an amount of fluid pressure, which is capable of inducing fault opening. Although stress change promotes the potential of fault failure and reactivation, the rate at which fluid pressurization within the fault zone generates variations in pore pressure as fault geometry changes during geothermal energy production have not been thoroughly addressed to include the effects of joint orientation. This study examines how different fault/joint models result in different tendency of injection-induced shear failure, and how this could influence the production rate. Here, a numerical simulation method is adopted to investigate the thermo-hydro-mechanical (THM) response of the various fault/joint models during production in a geothermal reservoir. The results indicate that pore pressure evolution has a direct relationship with the evolution of production rate for the three joint models examined, and the stress sensitivity of the individual fault/joint model also produced an effect on the production rate. Changing the position of the injection well revealed that the magnitude of shear failure on the fault plane could be controlled by the hydraulic diffusivity of fluid pressure, and the production rate is also influenced by the magnitude of stress change at the injection and production wells. Overall, the location of the injection well along with the fault damage zone significantly influenced the resulting production rate, but a more dominating factor is the joint orientation with respect to the maximum principal stress direction. Thus, the rate of thermal drawdown is affected by pore pressure elevation and stress change while the fault permeability and the production rate are enhanced when the joint’s frictional resistance is low.

scholarly journals Dilatancy stabilises shear failure in rock

2021 ◽  
Author(s):  
Franciscus Aben ◽  
Nicolas Brantut
Keyword(s):  
Pore Pressure ◽  
Fault Zone ◽  
Shear Failure ◽  
Rock Fracture ◽  
Fluid Pressure ◽  
Fault Slip ◽  
Pore Fluid ◽  
Lithostatic Pressure ◽  
Strengthening Effect ◽  
Pore Fluids

<p>Failure and fault slip in crystalline rocks is associated with dilation. When pore fluids are present and drainage is insufficient, dilation leads to pore pressure drops, which in turn lead to strengthening of the material. We conducted laboratory rock fracture experiments with direct in-situ fluid pressure measurements which demonstrate that dynamic rupture propagation and fault slip can be stabilised (i.e., become quasi-static) by such a dilatancy strengthening effect. We also observe that, for the same effective pressures but lower pore fluid pressures, the stabilisation process may be arrested when the pore fluid pressure approaches zero and vaporises, resulting in dynamic shear failure. In case of a stable rupture, we witness continued after slip after the main failure event that is the result of pore pressure recharge of the fault zone. All our observations are quantitatively explained by a simple spring-slider model combining slip-weakening behaviour, slip-induced dilation, and pore fluid diffusion. Using our data in an inverse problem, we estimate the key parameters controlling rupture stabilisation, fault dilation rate and fault zone storage. These estimates are used to make predictions for the pore pressure drop associated with faulting, and where in the crust we may expect dilatancy stabilisation or vaporisation during earthquakes. For intact rock and well consolidated faults, we expect strong dilatancy strengthening between 4 and 6 km depth regardless of ambient pore pressure, and at greater depths when the ambient pore pressure approaches lithostatic pressure. In the uppermost part of the crust (<4 km), we predict vaporisation of pore fluids that eliminates dilatancy strengthening. The depth estimates where dilatant stabilisation is most likely coincide with geothermal energy reservoirs in crystalline rock (typically between 2 and 5 km depth) and in regions  where slow slip events are observed (pore pressure that approaches lithostatic pressure). </p>

scholarly journals Assessment of Energy Production in the Deep Carbonate Geothermal Reservoir by Wellbore-Reservoir Integrated Fluid and Heat Transport Modeling

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-18 ◽  
Author(s):  
Fengyu Li ◽  
Tianfu Xu ◽  
Shengtao Li ◽  
Bo Feng ◽  
Xiaofeng Jia ◽  
...  
Keyword(s):  
Production Rate ◽  
Geothermal Energy ◽  
Energy Production ◽  
Fluid Transport ◽  
Clean Energy ◽  
Geothermal Reservoir ◽  
Injection Well ◽  
Heat Extraction ◽  
Stable Operation ◽  
Wellhead Pressure

Geothermal energy is clean and independent to the weather and seasonal changes. In China, the huge demanding of clean energy requires the geothermal energy exploitation in the reservoir with depth larger than 1000 m. Before the exploitation, it is necessary to estimate the potential geothermal energy production from deep reservoirs by numerical modeling, which provides an efficient tool for testing alternative scenarios of exploitation. We here numerically assess the energy production in a liquid-dominated middle-temperature geothermal reservoir in the city of Tianjin, China, where the heat and fluid transport in the heterogeneous reservoir and deep wellbores are calculated. It is concluded that the optimal injection/production rate of the typical geothermal doublet well system is 450 m3/h, with the distance between geothermal doublet wells of 850 m. The outflow temperature and heat extraction rate can reach 112°C and 43.5 MW, respectively. Through decreasing injection/production rate lower than 450 m3/h and optimizing layout of the injection well and production well (avoiding the high permeability zone at the interwell sector), the risk of heat breakthrough can be reduced. If the low permeability zone in the reservoir is around injection well, it usually leads to abnormal high wellhead pressure, which may be solved by stimulation technique to realize stable operation. The methodology employed in this paper can be a reference for a double-well exploitation project with similar conditions.

scholarly journals Production Optimization for Natural Flow and ESP Well A Case Study on Well NS-5 Mishrif Formation-Nasriya Oil Field

2020 ◽  
Vol 10 (2) ◽  
pp. 17-35
Author(s):  
Hamzah Amer Abdulameer ◽  
Dr. Sameera Hamd-Allah
Keyword(s):  
Production Rate ◽  
Production Optimization ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Pump Frequency ◽  
Individual Parameter ◽  
Well Production ◽  
Well Design ◽  
Natural Flow ◽  
Reservoir Conditions

As the reservoir conditions are in continuous changing during its life, well production rateand its performance will change and it needs to re-model according to the current situationsand to keep the production rate as high as possible.Well productivity is affected by changing in reservoir pressure, water cut, tubing size andwellhead pressure. For electrical submersible pump (ESP), it will also affected by numberof stages and operating frequency.In general, the production rate increases when reservoir pressure increases and/or water cutdecreases. Also the flow rate increase when tubing size increases and/or wellhead pressuredecreases. For ESP well, production rate increases when number of stages is increasedand/or pump frequency is increased.In this study, a nodal analysis software was used to design one well with natural flow andother with ESP. Reservoir, fluid and well information are taken from actual data of Mishrifformation-Nasriya oil field/ NS-5 well. Well design steps and data required in the modelwill be displayed and the optimization sensitivity keys will be applied on the model todetermine the effect of each individual parameter or when it combined with another one.

scholarly journals Analysis of Siphon String Application to Optimize Gas Lift Injection

2021 ◽  
Vol 4 (2) ◽  
Author(s):  
Sofani Muflih ◽  
Silvya Dewi Rahmawati
Keyword(s):  
Flow Regime ◽  
Production Rate ◽  
Flow Condition ◽  
Production Optimization ◽  
Font Size ◽  
Additional Advantage ◽  
Offshore Area ◽  
Well Model ◽  
Production Period ◽  
Gas Lift

<p><span style="font-size: small;"><span style="font-family: Times New Roman;"><em>B-</em><em>X</em><em> well is an oil producing well at Bravo field in Natuna offshore area, which was completed at IBS zone using 5-1/2 inch tubing size. </em><em>However, after several years of production period, the well’s production rate decreased due to reservoir depletion, and experienced gas lift performance problem indicated by unstable flowing condition (slugging flow). In year 2020, Siphon String installation is applied to the well in order to give deeper point of gas lift injection and better well’s production. The additional advantage by having smaller tubing size (insert tubing) is to reduce the slugging flow condition. The analysis of this siphon string installation at the B-X well, technically will be performed by evaluating gas lift performance and the flow regime inside the tubing using a Well Model simulator. The simulation was developed based on the real well condition. Several sensitivity analysis were done through several cases such as: variation in depth of gas lift point of injection, and the length of the siphon string. The simulation was required to evaluate the effectiveness of the existing installation, and to give better recommendation for the other well that has the same problem.  The result indicates that the depth of the current siphon string installation has been providing the optimum production rate, while the slugging flow condition will still be occurred at any given scenario of the siphon string depth due to the very low of well’s productivity. The similar procedure and evaluation can be implemented to other oil wells using gas lift injection located either in offshore or onshore field. </em></span></span></p><p><em><span style="font-family: Times New Roman; font-size: small;"> </span></em></p><p><em><span style="font-family: Times New Roman; font-size: small;">Keywords: Production Optimization, Siphon String, Flow Regime</span></em></p>

scholarly journals Characterizing microseismicity at the Rotokawa and Ngatamariki geothermal fields

2021 ◽  
Author(s):  
◽  
Chet Hopp
Keyword(s):  
Matched Filter ◽  
Fluid Pressure ◽  
B Value ◽  
Injection Well ◽  
Taupo Volcanic Zone ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Small Magnitude ◽  
Magnitude Distribution ◽  
Geothermal Fields

<p>In this thesis, we construct a four-year (2012–2015) catalog of microearthquakes for the Ngatamariki and Rotokawa geothermal fields in the Taupō Volcanic Zone of New Zealand, and use these data to improve the knowledge of reservoir behavior. These microearthquakes occur frequently, often every few seconds, and therefore provide a tool that we use to assess reservoir properties with dense spatial and temporal resolution as well as to illuminate the underlying processes of seismogenesis. Using a matched-filter detection technique we detect and precisely relocate nearly 9000 events, from which we calculate 982 focal mechanisms.  At Ngatamariki, these results constitute the first detailed analysis of seismicity at a newly-developed resource. It has been commonly assumed that induced shear on fractures increases reservoir permeability by offsetting asperities on either fracture wall, thereby propping the fracture open. During stimulation treatments of two boreholes (NM08 and NM09), borehole permeability experiences logarithmic growth. At NM08, this growth occurs for eight days in the absence of seismicity, while at NM09 only nine microearthquakes are observed during the one-month treatment. This suggests that hydro-shear, the process of inducing seismicity through increased pore pressure at critically-stressed fractures, is not the dominant mechanism of permeability increase at many geothermal wells. Instead, aseismic processes, likely thermal and overpressure induced fracture opening, dominate well stimulation in high-temperature geothermal settings.  At Rotokawa, the earthquake frequency-magnitude distribution (b-value) is positively correlated with both proximity to major injection wells and depth. In an inferred pressure compartment near injection well RK23, b is ~1.18, but is <1.0 elsewhere, suggesting a connection between increased pore-fluid pressure and small-magnitude events. In addition, throughout the reservoir b increases from a value of ~1.0 at injection depth to almost 1.5 two kilometers below the reservoir, consistent with observations at volcanic areas elsewhere, but opposing the conventional wisdom that b-value is inversely proportional to differential stress.  Finally, the 982 focal mechanism observations that we invert for stress show a normal faulting regime throughout both reservoirs. At Rotokawa, a lowering stress ratio, v, after reintroduction of injection well RK23 (v drops from 0.9 to 0.2 over six months) indicates that anisotropic reservoir cooling affects the reservoir stress state through a process of preferential stress reduction.</p>

The role of geomechanical modeling in the measurement and understanding of geophysical data collected during carbon sequestration

2021 ◽  
Vol 40 (6) ◽  
pp. 413-417
Author(s):  
Chunfang Meng ◽  
Michael Fehler
Keyword(s):  
Pore Pressure ◽  
Fault Location ◽  
Mechanical Response ◽  
Fluid Pressure ◽  
Geophysical Data ◽  
Fluid Injection ◽  
Coupled Flow ◽  
Cap Rock ◽  
Stress And Deformation ◽  
Pressure Changes

As fluids are injected into a reservoir, the pore fluid pressure changes in space and time. These changes induce a mechanical response to the reservoir fractures, which in turn induces changes in stress and deformation to the surrounding rock. The changes in stress and associated deformation comprise the geomechanical response of the reservoir to the injection. This response can result in slip along faults and potentially the loss of fluid containment within a reservoir as a result of cap-rock failure. It is important to recognize that the slip along faults does not occur only due to the changes in pore pressure at the fault location; it can also be a response to poroelastic changes in stress located away from the region where pore pressure itself changes. Our goal here is to briefly describe some of the concepts of geomechanics and the coupled flow-geomechanical response of the reservoir to fluid injection. We will illustrate some of the concepts with modeling examples that help build our intuition for understanding and predicting possible responses of reservoirs to injection. It is essential to understand and apply these concepts to properly use geomechanical modeling to design geophysical acquisition geometries and to properly interpret the geophysical data acquired during fluid injection.

scholarly journals Optimizing Production Schedule of Coalbed Methane Wells Using a Stochastic Evolution Algorithm

2020 ◽  
Vol 2020 ◽  
pp. 1-19
Author(s):  
Qiujia Hu ◽  
Xianmin Zhang ◽  
Xiang Wang ◽  
Bin Fan ◽  
Huimin Jia
Keyword(s):  
Production Rate ◽  
Coalbed Methane ◽  
Optimization Problem ◽  
Production Optimization ◽  
Production Performance ◽  
Production Schedule ◽  
Schedule Optimization ◽  
Well Production ◽  
Control Frequency ◽  
Optimized Schedule

Production optimization of coalbed methane (CBM) is a complex constrained nonlinear programming problem. Finding an optimal decision is challenging since the coal seams are generally heterogeneous with widespread cleats, fractures, and matrix pores, and the stress sensitivities are extremely strong; the production of CBM wells needs to be adjusted dynamically within a reasonable range to fit the complex physical dynamics of CBM reservoirs to maximize profits on a long-term horizon. To address these challenges, this paper focuses on the step-down production strategy, which reduces the bottom hole pressure (BHP) step by step to expand the pressure drop radius, mitigate the formation damage, and improve CBM recovery. The mathematical model of CBM well production schedule optimization problem is formulated. The objective of the optimization model is to maximize the cumulative gas production and the variables are chosen as BHP declines of every step. BHP and its decline rate constraints are also considered in the model. Since the optimization problem is high dimensional, nonlinear with many local minima and maxima, covariance matrix adaptation evolution strategy (CMA-ES), a stochastic, derivative-free intelligent algorithm, is selected. By integrating a reservoir simulator with CMA-ES, the optimization problem can be solved successfully. Experiments including both normal wells and real featured wells are studied. Results show that CMA-ES can converge to the optimal solution efficiently. With the increase of the number of variables, the converge rate decreases rapidly. CMA-ES needs 3 or even more times number of function evaluations to converge to 100% of the optimum value comparing to 99%. The optimized schedule can better fit the heterogeneity and complex dynamic changes of CBM reservoir, resulting a higher production rate peak and a higher stable period production rate. The cumulative production under the optimized schedule can increase by 20% or even more. Moreover, the effect of the control frequency on the production schedule optimization problem is investigated. With the increases of control frequency, the converge rate decreases rapidly and the production performance increases slightly, and the optimization algorithm has a higher risk of falling into local optima. The findings of this study can help to better understanding the relationship between control strategy and CBM well production performance and provide an effective tool to determine the optimal production schedule for CBM wells.

scholarly journals The influence of fault reactivation on injection-induced dynamic triggering of permeability evolution

2020 ◽  
Vol 223 (3) ◽  
pp. 1481-1496
Author(s):  
Elif Cihan Yildirim ◽  
Kyungjae Im ◽  
Derek Elsworth
Keyword(s):  
Pore Pressure ◽  
Fluid Pressure ◽  
Fault Reactivation ◽  
Permeability Evolution ◽  
Fracture Permeability ◽  
Permeability Enhancement ◽  
Pressure Pulses ◽  
Fracture Sealing ◽  
Permeability Increase ◽  
Pressure Driven

SUMMARY Mechanisms controlling fracture permeability enhancement during injection-induced and natural dynamic stressing remain unresolved. We explore pressure-driven permeability (k) evolution by step-increasing fluid pressure (p) on near-critically stressed laboratory fractures in shale and schist as representative of faults in sedimentary reservoirs/seals and basement rocks. Fluid is pulsed through the fracture with successively incremented pressure to first examine sub-reactivation permeability response that then progresses through fracture reactivation. Transient pore pressure pulses result in a permeability increase that persists even after the return of spiked pore pressure to the null background level. We show that fracture sealing is systematically reversible with the perturbing pressure pulses and pressure-driven permeability enhancement is eminently reproducible even absent shear slip and in the very short term (order of minutes). These characteristics of the observed fracture sealing following a pressure perturbation appear similar to those of the response by rate-and-state frictional healing upon stress/velocity perturbations. Dynamic permeability increase scales with the pore pressure magnitude and fracture sealing controls the following per-pulse permeability increase, both in the absence and presence of reactivation. However, initiation of the injection-induced reactivation results in a significant increase in the rate of permeability enhancement (dk/dp). These results demonstrate the role of frictional healing and sealing of fractures at interplay with other probable processes in pore pressure-driven permeability stimulation, such as particle mobilization.

Fluid pressure response to undrained compression in saturated sedimentary rock

Geophysics ◽  
1986 ◽  
Vol 51 (4) ◽  
pp. 948-956 ◽  
Author(s):  
Douglas H. Green ◽  
Herbert F. Wang
Keyword(s):  
Pore Pressure ◽  
Effective Stress ◽  
Wave Attenuation ◽  
Fluid Pressure ◽  
Confining Pressure ◽  
Pressure Response ◽  
Additional Parameter ◽  
Seismic Wave Velocity ◽  
Specific Storage ◽  
Order Of Magnitude

The pore pressure response of saturated porous rock subjected to undrained compression at low effective stresses are investigated theoretically and experimentally. This behavior is quantified by the undrained pore pressure buildup coefficient, [Formula: see text] where [Formula: see text] is fluid pressure, [Formula: see text] is confining pressure, and [Formula: see text] is the mass of fluid per unit bulk volume. The measured values for B for three sandstones and a dolomite arc near 1.0 at zero effective stress and decrease with increasing effective stress. In one sandstone, B is 0.62 at 13 MPa effective stress. These results agree with the theories of Gassmann (1951) and Bishop (1966), which assume a locally homogeneous solid framework. The decrease of B with increasing effective stress is probably related to crack closure and to high‐compressibility materials within the rock framework. The more general theories of Biot (1955) and Brown and Korringa (1975) introduce an additional parameter, the unjacketed pore compressibility, which can be determined from induced pore pressure results. Values of B close to 1 imply that under appropriate conditions within the crust, zones of low effective pressure characterized by low seismic wave velocity and high wave attenuation could exist. Also, in confined aquifer‐reservoir systems at very low effective stress states, the calculated specific storage coefficient is an order of magnitude larger than if less overpressured conditions prevailed.

Evaluation of Induced Thermal Pressurization in Clearwater Shale Caprock in Electromagnetic Steam-Assisted Gravity-Drainage Projects

SPE Journal ◽  
2013 ◽  
Vol 19 (03) ◽  
pp. 443-462 ◽  
Author(s):  
Sahar Ghannadi ◽  
Mazda Irani ◽  
Rick Chalaturnyk
Keyword(s):  
Pore Pressure ◽  
Analytical Solutions ◽  
Oil Sands ◽  
Shear Failure ◽  
Gravity Drainage ◽  
Hydraulic Fractures ◽  
Low Permeability ◽  
Steam Assisted Gravity Drainage ◽  
Thermal Pressurization ◽  
Shale Formation

Summary Inductive methods, such as electromagnetic steam-assisted gravity drainage (EM-SAGD), have been identified as technically and economically feasible recovery methods for shallow oil-sands reservoirs with overburdens of more than 30 m (Koolman et al. 2008). However, in EM-SAGD projects, the caprock overlying oil-sands reservoirs is also electromagnetically heated along with the bitumen reservoir. Because permeability is low in Alberta thermal-project caprock formations (i.e., the Clearwater shale formation in the Athabasca deposit and the Colorado shale formation in the Cold Lake deposit), the pore pressure resulting from the thermal expansion of pore fluids may not be balanced with the fluid loss caused by flow and the fluid-volume changes resulting from pore dilation. In extreme cases, the water boils, and the pore pressure increases dramatically as a result of the phase change in the water, which causes profound effective-stress reduction. After this condition is established, pore pressure increases can lead to shear failure of the caprock, the creation of microcracks and hydraulic fractures, and subsequent caprock integrity failure. It is typically believed that low-permeability caprocks impede the transmission of pore pressure from the reservoir, making them more resistant to shear failure (Collins 2005, 2007). In cases of induced thermal pressurization, low-permeability caprocks are not always more resistant. In this study, analytical solutions are obtained for temperature and pore-pressure rises caused by the constant EM heating rate of the caprock. These analytical solutions show that pore-pressure increases from EM heating depend on the permeability and compressibility of the caprock formation. For stiff or low-compressibility media, thermal pressurization can cause fluid pressures to approach hydrostatic pressure, and shear strength to approach zero for low-cohesive-strength units of the caprock (units of the caprock with high silt and sand percentage) and sections of the caprock with pre-existing fractures with no cohesion.

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