Reservoir Overpressure Research Articles

Hydrocarbon Accumulation and Overpressure Evolution in Deep–Ultradeep Reservoirs in the Case of the Guole Area of the Tarim Basin

Usually, deep oil and gas accumulation is often controlled by strike–slip faults. However, in the Tarim Basin, deep Ordovician oil and gas accumulations are also found in areas far from the fault zone. The process of oil and gas accumulation in deep reservoirs far from strike–slip fault zones is still unclear at present. The source and evolution of Ordovician fluids were analyzed using inclusion geochemical methods and the U–Pb dating technique. The analysis of rare earth elements and carbon–oxygen–strontium isotopes in the reservoirs showed that the reservoirs were weakly modified by diagenetic fluid. The fluid was derived from the fluid formation during the same period as the seawater, and no oxidizing fluid invaded the reservoir. The late oil and gas reservoirs had good sealing properties. The U–Pb dating results combined with homogenization temperature data revealed that the first-stage oil was charged during the Late Caledonian Period, and the second-stage natural gas was charged during the Middle Yanshanian Period. The evolution of the paleo-pressure showed that the charging of natural gas in the Middle Yanshanian was the main reason for the formation of reservoir overpressure. The strike–slip fault zone was basically inactive in the Middle Yanshanian. During this period, the charged natural gas mainly migrated to the reservoir along the unconformity surface and the open strike–slip fault zone in the upper part of the Ordovician reservoir. The source of the fluid shows that the reservoir in the late stage had good sealing properties, and there was no intrusion of exogenous fluid. The overpressure in the reservoir is well preserved at present.

The evolution of clay mineral and its indication of hydrocarbons under overpressure: An example from the shale of the Qingshankou Formation in the Gulong Sag

The enrichment and development of shale oil are significantly influenced by the evolution of clay minerals. In this paper, the mineralogy and clay mineral crystallinity of shale samples from Wells X1, X2 and X3 in the Gulong Sag are characterized by X-ray diffraction analysis (XRD) and field emission scanning electron microscopy (FE-SEM). Geochemical parameters, including total organic carbon (TOC) and rock-eval pyrolysis, were also evaluated. The results reveal that illite in the shale primarily exists in the matrix, originating mainly from the transformation of smectite and I/S mixed layer. Chlorite in pores is predominantly formed through fluid precipitation and crystallization. The study area exhibits abnormal evolution of illite and I/S mixed layers, as well as the phenomenon of rapid chlorite growth under overpressure condition. The abnormal evolution of illite and I/S mixed layer may attribute to the inhibition of the conversion reaction from I/S mixed layer to illite. Chlorite's rapid growth occurs through the nucleation mechanism. Furthermore, through the analysis of clay and organic matter correlation, coupled with overpressure and hydrocarbon-rich section considerations, it is observed that chlorite may play a significant role in the storage and generation of S1. This study contributes to a better understanding of the relationship between clay mineral evolution and shale reservoir overpressure, offering valuable insights for the accurate assessment of shale oil.

The effect of lunar declination on CO<sub>2 </sub>degassing from central Italian Apennines

<p>The periodical degassing from CO<sub>2</sub> over-pressured reservoirs may have serious consequences for the environment making urgent understanding the processes and forecasting the frequency. Prediction though needs methods that depends from temporal and spatial properties of hydro-chemical and physical reservoir characteristics that unfortunately are often lacking. We have analyzed surface emissions of CO<sub>2</sub> attributed to over-pressured CO<sub>2</sub>-rich reservoirs in the Central Italian Apennines a zone characterized by significant periodical CO<sub>2</sub> degassing. Here aquifers are hosted in Mesozoic limestone with high pCO<sub>2</sub> groundwater and travertine deposits. We analyzed a 10-year temporal series and found that in the Apennines CO<sub>2</sub> flux and aquifer fluid composition are correlated with the lunar tides. In particular, our study reveals that low CO<sub>2</sub> flux corresponds with low lunar tidal potential values. We found a similar trend for dissolved calcium and water alkalinity, while pH values display a linear correlation with tidal cycles. The forces associated with tidal potentials are not capable of fracturing rock. However, they can, under certain conditions, drive the flow of fluids in over-pressured reservoirs, triggering sub-surface fluid movements that in turn modify the water�Crock reactivity. In the central Apennines, we show that these movements result in increased dolomite dissolution and an eventual return to calcite equilibrium. In this case, dolomite dissolution breaks the rock releasing calcium into ground water, which leads to calcite equilibrium and in turn to the formation of significant quantities of travertine and the concomitant release of CO<sub>2</sub> in the atmosphere.</p>

Generation and distribution of overpressure in ultra-deep carbonate reservoirs controlled by intra-cratonic strike-slip faults: The Ordovician of Shuntuoguole area in the Tarim Basin

The strike-slip fault-controlled ultra-deep fractured-vuggy carbonate reservoir is an increasingly important exploration target. However, the high heterogeneity of fault-controlled reservoirs and the ineffective methods available for pressure prediction make it difficult to assess the risk of potential overpressure in ultra-deep carbonate reservoirs. Abnormal overpressure is common in the ultra-deep strike-slip fault-controlled carbonate reservoirs in the Shunbei Oilfield of the Tarim Basin. According to measured pressures, petroleum accumulation history, and fault framework, this study investigates the generation mechanisms of overpressure in fault-controlled carbonates and reconstructs the pressure evolution of reservoirs. Finally, the effect of strike-slip faults on current overpressure distribution is discussed. Measured pore pressure data from 90 wells showed that all reservoirs present in the major fault zones are normally pressured, and the reservoirs present far away from the major faults commonly develop overpressures. The distribution patterns of overpressure in the Middle-Lower Ordovician reservoirs coincide with areas with fault reactivation during the Himalayan Period. The results of the comprehensive analysis of petroleum accumulation history, fault activity, and well production suggested that dry gas generation is a primary cause of overpressure in the Middle-Lower Ordovician reservoirs. The relatively low temperature in the reservoir, in addition to the highly compartmentalized nature of overpressure, indicated that these overpressured gas migrate vertically into the Ordovician formation from deep strata along strike-slip faults. The pressure evolution restored by basin modelling and fluid inclusion showed that distinct differences in overpressure magnitude in the different reservoirs were formed at the stage of gas charging but not at the early stages of oil accumulation. The difference in physical properties of the two types of fault-controlled reservoirs resulted in different pressure distributions and oil-bearing levels in the ultra-deep carbonate reservoirs at present. The strike-slip fault zones are the primary pathways by which overpressured fluids migrate from the deeper Cambrian formation into the Ordovician reservoirs and act as barriers to separate the pressure systems in the ultra-deep carbonate reservoirs. These findings are expected to help mitigate the drilling risks with overpressure in deep strike-slip fault-controlled carbonate reservoirs.

The effect of coupling of tectonic compression and overpressure on porosity of deep reservoirs: a case study of southern margin of Junggar Basin, northwest China

The majority of high quality clastic reservoirs in the foreland basins, northwest China have anomalously high primary porosity. The intensive tectonic compression, overburden and overpressure importantly impact on the deep reservoir quality in the foreland basins, and that very little research had been so far conducted on this topic. Only considering mechanical compaction without chemical diagenesis, various geological models of tectonic compression, overpressure and porosity were simulated using a comprehensive numerical model. Based on the simulations, the influences of the coupling tectonic compression and overpressure on porosity in deep reservoirs are quantitatively discussed. A case study using a representative well in the thrust belt of the Junggar foreland basin is simulated. The results show that the porosity formed from the early-middle slow burial and late rapid burial type is higher than the almost constant burial type and the early rapid burial and then slow burial type, when the overpressure is formed by the three burial types couple with the same tectonic compression. Importantly, overpressure formed during the early-middle slow burial and late rapid burial type in concert with tectonic compression best preserves high porosity within reservoirs. Either increasing tectonic compression stress early at constant overpressure or increasing the tectonic compression stress at a relative late stage and increasing reservoir overpressure can contribute to porosity loss. The porosity decreases more rapidly in the former case. The later the tectonic compression was applied, the more rapidly porosity of the reservoir decreased. Therefore, late stage tectonic compression accompanied by overpressure has the largest influence on the porosity. The porosity of the Qigu Formation in the well Ds1 in the south margin of Junggar Basin, for example, was decreased by 0.88% in response to intensive tectonic compression in the late Himalayan orogeny. However, porosity formed by overpressure suppression and preservation in the reservoir is 3.66%. So, in addition to vertical compaction and diagenesis, the influence of tectonic compression and overpressure should also be considered in the study of deep reservoir porosity evolution in foreland basin. This study can be helpful for deeply understanding the evolution rule of deep reservoir porosity in foreland basin.

Vertically transferred overpressures along faults in Mesozoic reservoirs in the central Junggar Basin, northwestern China: Implications for hydrocarbon accumulation and preservation

Abnormally high pressure (overpressure) is common in oil reservoirs of the Mesozoic formations in the central Junggar Basin. However, the generation mechanisms of overpressure are still uncertain, which not only affects safe drilling implementation, but also restricts the understanding of hydrocarbon migration and accumulation. Based on measured pressures and mud weights, the pore pressure distributions in the Mesozoic formations are characterized in detail. The different generation mechanisms of overpressure in mudstones and sandstones are investigated based on logging responses and basin modeling. Finally, the significance of reservoir overpressure to oil accumulation and leakage is discussed. The results indicate that overpressure in the Mesozoic reservoirs in the central Junggar Basin is mainly developed below 4500 m, the excess pressures are between 12 and 58 MPa, the pressure gradient ranges from 12 to 21 MPa/km, the pressure ratios range from 0.6 to 0.95, and the overpressure ratios are between 0.25 and 0.91. The high-overpressure in reservoirs is mostly present in isolated sand bodies that are hydraulically connected to Permian source rocks by faults. The overpressure data corresponding to a pressure gradient of 11–14 MPa/km plot on the loading curve, showing typical disequilibrium compaction overpressure. The points with pressure gradients greater than 14 MPa/km obviously deviate from the loading curve, indicating unloading overpressure mechanisms. The logging responses and numerical simulation results confirm that the overpressure in mudstone is mainly generated by disequilibrium compaction and chemical compaction, and hydrocarbon generation has a limited contribution. The unloading overpressure in the sandstone is mainly generated by the vertical overpressure transfer process from the deep Permian overpressured compartment. The vertical transfer of overpressure is often related to oil migration and accompanied by high oil saturations. However, high-overpressure presents challenges for the sealing capacity of caprocks. Hydrofracturing or the activation of preexisting faults due to high overpressure determines the risk of seal failure, which controls hydrocarbon leakage. The research is of great significance for understanding the mechanisms of hydrocarbon migration along faults and evaluating caprock integrity in similar basins.

Reservoir Overpressure in the Mahu Sag, Northwestern Junggar Basin, China: Characteristics and Controlling Factors

Reservoirs with overpressure are of great importance for petroleum exploration where commercial production can be usually obtained. Studying the distribution characteristics and controlling factors of reservoir overpressure is crucial for further petroleum exploration. In this study, we investigate the vertical and planar distribution of reservoir overpressure in the Mahu sag, northwestern Junggar basin by analyzing measured pressure data from well testing of oil reservoirs. In the Baikouquan-Jiamuhe Formation, reservoir overpressure is widely distributed, and the pressure coefficient increases from the margin to the center of the sag and generally increases with the increasing altitude. Crossplot analysis of density and velocity in the Triassic strata and Permian Fengcheng Formation is conducted to further investigate the influence of undercompaction in the Mahu sag for the first time. The result suggests that undercompaction has little influence on reservoir overpressure, whereas fluid charging may play a vital role in the development of overpressure. Our research further conducted the analyses of distribution of source rocks and oil-source correlation. The results further confirmed that hydrocarbon generates from the Fengcheng Formation and charges into other reservoirs, suggesting that hydrocarbon generation and fluid charging are the main mechanism of reservoir overpressure.

Concurrent 1. Presentation for: The role of faulting in Northern Carnarvon’s sub-basins in transferring very high overpressure

Presented on Tuesday 17 May: Session 1 Australia’s Northern Carnarvon Basin has experienced a varied geological history with periods of extension and thermal subsidence giving rise to separate sub-basins. Between the sub-basins the sequences of strata, their age, depth and rate of burial, and rock type vary greatly. Contrasts in rock type and burial rates are key variables that control generation of overpressure and, as such, create a wide range of pore pressure conditions from hydrostatic pressure to overpressure levels approaching values of vertical stress. Often these contrasting pressures can be situated relatively proximal to one another in both a horizontal and lateral sense. To improve pre-drill prediction capabilities for well planning in Northern Carnarvon, a study was completed in 2013 that included over 600 exploration wells and included reporting on areas at increased risk of high overpressure. One of the study findings was that reservoirs at sub-basin boundaries were often where the pressure was most variable and difficult to predict. The reason pressure was difficult to predict in these areas was due to high overpressure being transferred via faults at the margin of early Jurassic to early Cretaceous depocentres. In 2015, Hoskin et al. published the paper ‘Influence of faulting on reservoir overpressure distribution in the Northern Carnarvon Basin’ and this extended abstract looks at the Winchester-1 well, drilled after data were compiled for the original study, that validates the model presented in 2015, and also poses additional questions about the transfer of pressure. To access the presentation click the link on the right. To read the full paper click here

The role of faulting in Northern Carnarvon’s sub-basins in transferring very high overpressure

Australia’s Northern Carnarvon Basin has experienced a varied geological history with periods of extension and thermal subsidence giving rise to separate sub-basins. Between the sub-basins the sequences of strata, their age, depth and rate of burial, and rock type vary greatly. Contrasts in rock type and burial rates are key variables that control generation of overpressure and, as such, create a wide range of pore pressure conditions from hydrostatic pressure to overpressure levels approaching values of vertical stress. Often these contrasting pressures can be situated relatively proximal to one another in both a horizontal and lateral sense. To improve pre-drill prediction capabilities for well planning in Northern Carnarvon, a study was completed in 2013 that included over 600 exploration wells and included reporting on areas at increased risk of high overpressure. One of the study findings was that reservoirs at sub-basin boundaries were often where the pressure was most variable and difficult to predict. The reason pressure was difficult to predict in these areas was due to high overpressure being transferred via faults at the margin of early Jurassic to early Cretaceous depocentres. In 2015, Hoskin et al. published the paper ‘Influence of faulting on reservoir overpressure distribution in the Northern Carnarvon Basin’ and this extended abstract looks at the Winchester-1 well, drilled after data were compiled for the original study, that validates the model presented in 2015, and also poses additional questions about the transfer of pressure.

Seismic Work Flow Characterizes Deep, Thin Formation Layers Offshore South China Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30164, “Deep and Thin Overpressure Reservoir Characterization of Paleogene Wenchang Formation in the Enping 17 Sag of the South China Sea,” by Jun Liu and Yingwei Li, CNOOC, and Donghai Liang, Schlumberger, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. The complete paper describes an integrated work flow for 3D seismic reservoir characterization of offshore deep and thin layers in the Eocene Wenchang formation (WCF) without sufficient well data. The work flow includes seismic data reprocessing, well-log-based rock physics analysis, seismic structure interpretation, 3D simultaneous amplitude variation with offset (AVO) inversion, 3D lithology prediction, and geological integrated analysis. Formation Development and Objectives The Pearl River Mouth basin (PRMB) on the northern continental margin of the South China Sea has undergone multistage extensional rifts. The Enping Sag lies in the Zhu1 depression, north of the PRMB, and consists of three subsags. Enping 17 is the largest and deepest sag, with an area of 550 km2, and the thickness of Eocene sediments is greater than 3000 m. The deep middle Eocene WCF, with gray lacustrine mudstones, is hydrocarbon-rich and is the major source rock in the area. A wildcat well had penetrated the WCF at an area with a vertical thickness of 380 m. During drilling, the mud weight was increased to 1.46 g/cm3 from 4570 m total vertical depth (TVD) downward because of increasing pore pressure and higher background gas abnormalities in the WCF. A high pore-pressure gradient of 14.5 KPa/m was measured by drillstem test (DST) at a depth of 4641.5 m TVD. Under the protection of the high pore pressure, the high-quality reservoir layer from 4642 to 4651 m TVD was encountered with 12% average porosity, 3.6-md permeability, and 47.1% saturation. Although a hydrocarbon sample was not obtained during the downhole test because of technical restrictions of DST in 1985, gas surge and a small amount of gas and condensate oil were observed after the test instruments were pulled to surface. With the subsequent development of field techniques, it was likely that current drilling and DST techniques could achieve productive oil flow in this layer.

Present-day overpressure in southern Tunisia: Characterization, possible causes and implications for drilling operations

Formation pore pressure in sedimentary basins is known to vary with depth. These variations are caused by one or more sedimentary, tectonic or diagenetic mechanisms. In Mesozoic basins of southern Tunisia, a detailed study has been carried out in order to characterize the regional pore pressure profile. The results show an over-pressure interval ranging from upper Triassic to lower Jurassic salts series.The study of possible overpressure mechanisms allows us to conclude that the present-day overpressure can be explained by the active compressional tectonics that is affecting the North African margin. Nevertheless, other past overpressures have been interpreted from this study and have been attributed to different mechanisms. One of the most important paleo-overpressure mechanisms was gypsum dehydration. This diagenetic reaction has led to pore pressure approaching lithostatic pressure, demonstrated by hydraulic fractures and beef veins observed in fields.In this study, we established a method based on a depth chart diagram enabling the identification of the likely mechanism involved in reservoir overpressure build-up and/or the prediction of a potential mechanism. This result could be important in the analysis of unexplored basins to predict the anticipated pressure profile and thereby reduce the risk of encountering unexpected overpressured zones and related drilling hazards. This method could be applied to other sedimentary basins with standard geological backgrounds.

Overpressure generation by disequilibrium compaction or hydrocarbon generation in the Paleocene Shahejie Formation in the Chezhen Depression: Insights from logging responses and basin modeling

Abundant oil resources associated with overpressure have been confirmed to be present in the Paleogene Shahejie Formation in the Chezhen Depression. Pore pressure strongly influences the migration and trapping of hydrocarbons and impacts the safety of drilling operations. The origin of the overpressure and the relationship between overpressure and hydrocarbon migration are not clearly understood in the Chezhen Depression, which has brought difficulties in prospect evaluation and during drilling. According to the measured pressures, mud weights, logging responses, and basin modeling results, the possible overpressure mechanisms in the Shahejie Formation in the Chezhen Depression are revealed, and the distribution of overpressure and its implications for oil migration dynamics are discussed. The overpressure in the Shahejie Formation is mainly concentrated in Es3 and Es4, and the distribution of overpressure in reservoirs is complex. The disequilibrium compaction of rapidly buried Paleocene mudstones is a common overpressure mechanism in the Chezhen Depression, and the overpressure points in acoustic transit time-vertical effective stress, density-vertical effective stress and acoustic transit time-density cross plots follow the loading curves. Hydrocarbon generation has played an important role in overpressure generation at depth in the center of the Chezhen Depression. The acoustic transit time of high-overpressured intervals shows more anomalies than the density measurements, and the overpressure points fall on the unloading curves in rock property-vertical effective stress cross plots. However, overpressure due to hydrocarbon generation rarely occurs in isolation and always appears simultaneously with disequilibrium compaction. The transfer of overpressure often complicates the pressure distribution in sandstones, leading overpressure and normal pressure to occur at similar depths. The overpressure in the Chezhen Depression promoted oil migration and improved the efficiency of oil accumulation. In particular, overpressure was the main force driving the migration of the oil generated in the Es3u downward to the Es4 reservoirs. Knowledge of the mechanisms and distributions of overpressure has great significance for further exploration in the Chezhen Depression and other extensional basins.

Horizontal tectonic stress as a cause of overpressure in the southern margin of the Junggar Basin, northwest China

Overpressure can be widely observed in the Jurassic, Cretaceous and Paleogene reservoirs in the southern margin of the Junggar Basin, northwest China. The study region was subjected to intense tectonic stress from the neighbouring North Tianshan Mountains since the Miocene. However, the causes of tectonic stress-induced overpressure are still poorly understood. In this study, we considered the plots of sonic velocity against density and vertical effective stress and applied numerical simulations and geological analysis to determine the origin of overpressure with respect to mudstone and sandstone in the area under study by investigating the compaction of mudstone and analysing the overpressure distribution. Our results indicate that the most overpressured mudstone in the second and third structural belts and the east of the Sikeshu Sag exhibits abnormally high porosity, which is obvious from the regional seal mudstone of the Paleogene Anjihaihe and Lower Cretaceous formations. The overpressure in these mudstones can be mainly attributed to the increase in vertical stress and horizontal tectonic stress (HTS). The current overpressures in the reservoir sandstone of the second and third structural belts as well as towards the east of the Sikeshu Sag are mainly induced by HTS, overpressure transfer and increase in vertical stress. The contribution of the overpressure associated with the generation of HTS to the total overpressure differs in different belts. This contribution ranges from 28.5% to 69.2%, 21.2%–46.2% and 16.3%–34.8% in the second, the third structural belts and the east of the Sikeshu Sag, respectively. Thus, HTS can be the primary contributor to the reservoir overpressure in many zones in the area under study.

Physical simulation experiment on porosity evolution and controlling factors of Miocene reservoir in Ledong-Lingshui Depression, Qiongdongnan Basin, South China Sea

Considering the high-temperature and overpressure in Miocene reservoirs of Ledong-Lingshui Depression, physical simulation experiments and other methods were adopted to identify the effect of overpressure on reservoir quality and the controlling factors of high-quality reservoir in porosity evolution process. In this paper, the temperature-pressure fields were divided into high-temperature normal-pressure (HTNP) zone, high-temperature overpressure (HTOP) zone, and high-temperature high-overpressure (HTHO) zone. The research findings are as follows: (1) The overpressure has a certain protective effect on primary pores. The visible porosity obtained from overpressure compaction simulation experiment is much higher than that obtained from normal compaction simulation experiment in the same diagenetic stage. The differences of visible porosity between normal compaction and overpressure compaction and high overpressure compaction can reach 1.55% and 6.74% respectively. (2) The organic acid dissolution contributes greatly to the formation of secondary pores in reservoir. The difference of visible porosity between organic acid dissolution and normal compaction is 0.96–7.38%. But the meteoric water leaching has a limited impact on reservoir porosity with a difference of merely 0.19% between meteoric water leaching and normal compaction. (3) Organic acid dissolution has the greatest constructive effect on diagenesis under the HTNP. However, overpressure protection to primary pores is the leading contributor to high-quality reservoir under the HTOP and HTHO, and the protective effect is positively correlated with the increase of overpressure. Overall, this work provides new insights into the porosity evolution and controlling factors in reservoirs.

Supercritical Methane Adsorption on Shale over Wide Pressure and Temperature Ranges: Implications for Gas-in-Place Estimation

Methane adsorption experiments over wide ranges of pressure (up to 30 MPa) and temperature (30-120 °C) were performed using a gravimetric method on the Longmaxi shale collected from the northeast boundary of Sichuan Basin, China. Organic geochemical analyses, shale composition determination, and porosity tests were also conducted. The experimental supercritical methane excess adsorption isotherms at different temperatures initially increase and then decrease with increasing pressure, giving a maximum excess adsorption capacity (Gexm = 1.86-2.87 cm/g) at a certain pressure P (6.71-12.90 MPa). The excess adsorption capacity decreases with increasing temperature below 28 MPa, while this effect reversed above 28 MPa. However, the absolute adsorption capacity decreases as the temperature increases over the full pressure range. Supercritical methane adsorption on shale is of temperature dependence because it is a physical exothermic process supported by calculated thermodynamic parameters. P is positively correlated with the temperature, while the decline rates (0.021-0.058 cm g MPa) in excess adsorption negatively correlate with the temperature. Meanwhile, Langmuir volume G (3.07-4.04 cm/g) decreases while Langmuir pressure P (1.44-4.31 MPa) increases with temperature elevation. In comparison to the actual adsorbed gas (absolute adsorption), an underestimation exists in the excess adsorption calculation, which increases with increasing depth. The conventional method, without subtracting the volume occupied by adsorbed gas, overestimates the actual free gas content, especially for the deep shale reservoirs. In situ adsorbed gas is simultaneously controlled by the positive effect of the reservoir pressure and the adverse effect of the reservoir temperature. Nevertheless, in situ free gas is dominated by the positive effect of the reservoir pressure. Lowerature overpressure reservoirs are favorable for shale gas enrichment. Geological application of gas-in-place estimation shows that, with increasing depth, the adsorbed gas content increases rapidly and then declines slowly, whereas the free gas content increases continuously. There was an equivalence point at which the contents of adsorbed and free gas are equal, and the equivalence point moved to the deep areas with increasing water saturation. Moreover, the adsorbed gas and free gas distribution are characterized by the dominant depth zones, providing the reference for shale gas exploration and development.

Physical simulation experiments on pore evolution in high-temperature and overpressure reservoirs

At present, simulation on reservoir evolution under normal pressure is common while that under abnormal pressure is rare. In this paper, the Miocene “high-temperature and overpressure” reservoir in the Ledong–Lingshui Sag of the Qiongdongnan Basin was taken as the research object to quantitatively define the effects of high pressure and overpressure on the evolution of reservoir pores. After the temperature and pressure field in this area was divided in the setting of sedimentation and diagenesis, the evolution characteristics of pores in different temperature and pressure field were analyzed by means of natural analogy and physical simulation experiment. Then, the effects of overpressure and fluids on the evolution of reservoir pores were discussed. Finally, the main factors controlling the development of high-quality reservoirs were determined. And the following research results were obtained. First, the temperature and pressure field of the Miocene reservoir in the Ledong–Lingshui Sag can be divided into three zones, i.e., high temperature and normal pressure zone, high temperature and overpressure zone, and high temperature and super overpressure zone. Second, overpressure and super overpressure can provide some preservation on primary pores. In the same diagenetic stage, the plane porosity of overpressure and super overpressure reservoirs is 1.23–6.74% higher than that of normal pressure reservoirs. Once the reservoir pressure in overpressure and super overpressure areas is higher than hydrostatic pressure by 8 MPa and 4 MPa, respectively, about 1% primary pores are preserved. Third, the dissolution of organic acid makes greater contribution to the secondary pores in reservoirs and its plane porosity is 0.96–7.38% higher than that of normal compaction reservoirs. Fourth, the leaching effect of meteorological water on reservoir physical properties is slight, and its plane porosity is only 0.19% higher than that of normal compaction reservoirs. In conclusion, the dissolution of organic acid is the most constructive effect for the reservoirs in high temperature and normal pressure. In addition, preservation of primary pores by overpressure is the most constructive effect for the reservoirs in high temperature and (super) overpressure, and the higher the overpressure is, the more preservation effect it provides on pores.

Heterogeneity in the overpressure zones in West Baram Delta, offshore-Sarawak, Malaysia

Geopressure prediction is crucial because all drilling programs require estimation of abnormal pressured zones. The use of rock fabric deformational relics at variable depths to determine heterogeneity in overpressure zones in reservoir has not been explored. Therefore, the aim of this paper is to use petrography to determine intrinsic variations within overpressure zones. Understanding petrographic expression of overpressure on reservoir lithofacies at variable depths will enhance the prediction of overpressure in reservoirs that are not initially logged by subsurface pressure detecting tools. Thin section and scanning electron microscopy (SEM) petrography was used to study rock fabric. The petrophysical properties of the rock samples were measured using mercury porosimetry. Two lithofacies were discretized in a single reservoir i.e., massive friable fine-grained sandstone (MFFS) (Layer 1) and massive fine-grained sandstone (MFS) (Layer 2). The underlying layer (Layer 2) is dominated by sutured quartz grains, lenticular grain orientation, quartz overgrowth and relatively low porosity and permeability. The quartz grains are polycrystalline and characterized by planar and conchoidal fractures, in contrast to the overlying MFFS layer dominated by monocrystalline and platy quartz grains. The petrographic studies show overpressure variation can be characterized intrinsically by quartz deformational features and overall texture differences.

Testing the efficacy of active pressure management as a tool to mitigate induced seismicity

Manipulation of subsurface stresses through fluid injection/extraction may induce seismicity through modulation of overpressure along faults. Globally, most industrial operations do not induce significant earthquakes. However, the possibility of inducing moderate to large earthquakes is recognized as a significant risk for basin-scale carbon dioxide (CO2) storage operations (Niass et al., 2017). One possible method to reduce the occurrence of induced seismicity is to maintain only small (or zero) fluid overpressure changes in the subsurface through extraction of formation brine. For active pressure management (APM), operators may employ different procedures including extraction of various brine volumes and different configurations of injection/extraction well locations. However, the impact each these operational procedures on induced seismicity must be understood in order to develop management strategies.Here, we describe a numerical modeling workflow to evaluate the efficacy of APM techniques, that when applied to a specific site may be used to inform operational management strategies. We couple the multiphase reservoir model, NUFT, with the earthquake simulator, RSQSim and simulate seismicity induced by CO2 injection into a hypothetical brine saturated reservoir. Reservoir overpressure is modified by co-extraction of brine at various fractions of the injected CO2 volume from five potential wells. Our goal is to understand how the well-pair configuration and the extracted brine volume impact the total number and the maximum event magnitude. Additionally, the performance of each scenario is also evaluated in terms of the volume of CO2 that can be stored before an earthquake above a tolerance threshold is induced.

Fluid energy characteristics and development potential of coalbed methane reservoirs with different synclines in Guizhou, China

Reservoir fluid energy is an important parameter that restricts the productivity of coalbed methane (CBM), and is crucial for CBM exploration and development. In this study, data from 41 pumping tests and 37 water quality analyses from 8 syncline coal-bearing strata in Guizhou were collected. The results show that the equivalent reservoir pressure increases linearly with an increase in burial depth. The Changgang (CG) syncline belongs to an overpressure reservoir, the Yizhitang (YZT) syncline and the Yangmeishu (YMS) syncline belong to low pressure reservoirs, and the other syncline reservoirs are close to neutral pressure states. The hydrodynamic conditions of the Panguan (PG), Tucheng (TC) and Dahebian (DHB) synclines are stronger, those of the CG syncline are weaker, and those of the Huangnitang (HNT), Bide (BD), YZT and YMS synclines are relatively normal. The water quality types are divided into three types, namely, NaHCO3, Ca(HCO3)2 and CaSO4. The water quality for the CG, DHB, TC, PG and YMS synclines are of the NaHCO3 types, which shows a relatively closed groundwater environment. The water quality types of the HNT and YZT synclines are of the Ca(HCO3)2 type, which shows a relatively open groundwater environment. The water quality for the BD syncline are of the NaHCO3 and CaSO4 types, which indicates that the groundwater environment of coal-bearing strata in the BD syncline is complex and has the characteristics of both closed and open mixed environments. Furthermore, the principal component analysis method (PCA) was used to select 6 parameters and to select the DHB syncline as having the most development potential, followed by the PG syncline and the TC syncline. Validating these results with CBM development wells, the evaluation results were found to be in good agreement with the actual productivity of the CBM wells.

Effects of smectite dehydration and illitisation on overpressures in sedimentary basins: A coupled chemical and thermo-hydro-mechanical modelling approach

Diagenetic smectite dehydration and smectite-to-illite transition in clay-rich sediments can contribute to the generation of overpressure in sedimentary basins, because of the release of water associated with these mineralogical reactions. However, the challenge of deciphering the contribution of smectite dehydration and illitisation to fluid pressure amongst other mechanisms generating overpressure requires the different mechanisms at play to be jointly considered. Here, we developed a coupled chemical and thermo-hydro-mechanical code, named SURP, to calculate the overpressure generation in a sedimentary pile because of sediment compaction during its burial, temperature increase, water flow and because of the release of water by clay dehydration and illitisation. For this purpose, a revised thermodynamic model describing smectite dehydration by a solid solution approach was considered, together with the different thermo-hydro-mechanical processes occurring in sedimentary basins. The SURP code was applied to the case study of an overpressured passive margin in the Niger Delta, composed of thick shale layers in a sedimentary pile. In this geological scenario, smectite dehydration was simulated and could explain 10–30% (20–50 bar) of the present day overpressure in the main reservoirs, in addition to compaction disequilibrium.