Overpressure Formation Research Articles

Estimation of Utsira CO2 Storage Capacity Based on Water Producing Modelling and Identification of Proper Water Producer Architecture

Utsira aquifer is well known from the CCS community as Sleipner gas project is storing CO2 in that aquifer since 1996. More than 17 million tons of CO2 have been injected to date. According to previous studies, CO2 storage capacity of the Utsira varies between 0.3 and 50.4 Gt. In this study, assuming specific parameters, the storage capacity is estimated about 1.7 Gt using analytical method. A full scale flow model of the aquifer has been used to model CO2 storage, considering CO2 migration and pressure raise to estimate the CO2 storage capacity, with or without water production. Water-CO2 relative permeabilities are selected based on a vertical equilibrium approach and validated when CO2 migration is compared to high resolution grid refinement around the injector areas. Optimizing injector well locations lead to an estimation of CO2 storage capacity of about 1.6 Gt without water production. This capacity can be increased to 3 Gt with about 1 Gt of formation water being produced during injection. The location and architecture of the water production wells were optimized: the wells should be subsea and should be operated with minimal requirement. Two production methods were compared: eruptive wells, producing water based on the formation overpressure induced by the CO2 storage; and activated wells using electrical submersible pumps (ESP). For each scenario, an optimization is proposed in terms of well count, well locations and well architecture designs. For the reservoir depth ranging between 500–1200 m below sea level and for such a high water production rate, the electrical submersible pumps (ESP) technology is a suitable application.

Drilling Optimization of Tight Sands and Shale Gas Reservoir in Jambi Sub-Basin Based on Pore Pressure Estimation Using Drilling Efficiency Mechanical Specific Energy (DEMSE) and Bowers Methods

The subsurface pressure analysis is used to detect the overpressure and problems in the well that will be drilled based on exploration well data. Various problems were found while drilling operations carried out on A and B wells, namely, Kick and Pipe sticking which cause a high Non-Productive Time (NPT). This research is conducted to identify the mechanism of overpressure formation in Tight Sand Gas and Shale Gas in the Jambi Sub-Basin. Furthermore, to predict pore pressure using the Drilling Efficiency and Mechanical Specific Energy (DEMSE) and Bowers method. The final result will be a 3D pore pressure cube in the area based on quantitative analysis of post-stack seismic inversion. The results of the pore pressure analysis from the wells and the 3D pore pressure model indicate that top of overpressure occurs in the Gumai Formation, then it is decreasing gradually approaching the hydrostatic pressure on the Basement. The mechanisms of overpressure are caused by under compaction, fluid expansion (kerogen maturation). The Gumai Formation and Talang Akar Formation are shale rocks so the type of mud weight that is well used is oil based mud (OBM).

Utility of inclusions for interpreting reservoir thresholds for tight sandstone gas accumulation in the Longfengshan and Dongling sags, Southeast China

To better understand the thresholds for hydrocarbon migration in tight sandstone, we studied the gas migration and accumulation processes in the Longfengshan and Dongling sags in the Songliao Basin by determining the ancient pore pressure evolution and gas fractionation. The trapping pressure of coeval aqueous inclusions can be used to identify systematic overpressure trends, which increase during gas charging. Early formation of overpressure and a maximum surplus pressure greater than 6 MPa in reservoirs adjacent to high-quality source rocks (total organic carbon > 1.2%) indicate that the formation of surplus pressure is related to the gas generation capacity. The gas-bearing inclusion distribution and systematic geochemical trends suggest that dynamic gas migration was accompanied by gas fractionation. The results indicate that dissolved gas mainly accumulated in reservoirs with a maximum surplus pressure greater than 6 MPa and that the free gas diffused toward reservoirs with maximum surplus pressures less than 6 MPa. The gas saturations were generally stable and greater than 50% in the high surplus pressure zone. However, in the low surplus pressure zone, the gas saturation was less than 25%, although this value was relatively higher in reservoirs where the maximum surplus pressure was less than 3 MPa. Our results demonstrate that the resistance thresholds for the migration of dissolved gas and free gas differ in tight sandstone reservoirs. The surplus pressures greater than 6 MPa are advantageous for dissolved gas accumulation. An obvious resistance threshold is not observed for free gas migration, although the migration of this gas was relatively inefficient and occurred mainly via diffusion in the direction of decreasing surplus pressure. The results of this study confirm the importance of considering the driving force for natural gas in different phases as a key factor when determining optimal exploration targets.

Formation condition of deep gas reservoirs in tight sandstones in Kuqa Foreland Basin

Due to the high expense of deep oil and gas exploration, prediction of gas-bearing properties before drilling is crucial for deep gas reservoir of tight sandstone. Deep tight sandstone gas fields in Kuqa Foreland Basin are characterized by high abundance, high gas saturation, high pressure, high and stable yield, which belong to high-efficiency tight gas reservoir. Based on theoretical analysis of controlling factors and mechanisms of gas-bearing properties for tight sandstone gas reservoir, and taking tight sandstone gas fields with high effectiveness such as Dibei, Keshen and Dibei gas fields in Kuqa Foreland Basin as examples, formation condition and mechanism of high-efficiency tight sandstone gas reservoir in Kuqa area are studied through a comparative analysis of typical tight sandstone gas reservoir in Sichuan Basin and Ordos Basin. The results show that the formation condition of deep gas reservoir of tight sandstone in Kuqa foreland basin includes four factors: i.e., overpressure gas charging, fracture development, “early-oil and late-gas” accumulation process and favorable preservation condition. The overpressure gas charging and fracture development are the most important factors for formation of high-efficiency tight gas reservoirs in Kuqa Foreland Basin. High-quality source rocks, high source-reservoir pressure difference, and overpressure filling induced thereby are preconditions for formation of tight sandstone with high gas saturation. The fracture development controls gas migration, accumulation, and high yield of tight sandstone gas reservoir. The reservoir wettability changed by the early oil charging is beneficial to late natural gas charging, and the preservation condition of high-quality gypsum cap rocks is the key factor for gas reservoirs to maintain overpressure and high gas saturation. Matching of above four favorable factors leads to the tight sandstone gas reservoir with high abundance, high gas saturation and high gas production in Kuqa Foreland Basin, which is very different from other basins. Under the condition of little difference in physical property of tight sandstone reservoir, excessive source-reservoir pressure difference, facture development, preservation condition and current formation overpressure are the most significant factors to be considered in exploration and evaluation of deep tight sandstone gas.

Suppression of vitrinite reflectance by bitumen generated from liptinite during hydrous pyrolysis of artificial source rock

Mean random vitrinite reflectance (Ro) is the most widely accepted method to determine thermal maturity of coal and other sedimentary rocks. However, oil-immersion Ro of polished rock or kerogen samples is commonly lower than Ro values measured in samples from adjacent vitrinite-rich coals that have undergone the same level of thermal stress. So-called suppressed Ro values have also been observed in hydrous pyrolysis experiments designed to simulate petroleum formation. Various hypotheses to explain Ro suppression, such as sorption of products generated from liptinite during maturation, diagenetic formation of perhydrous vitrinite or overpressure, remain controversial. To experimentally test for suppression of vitrinite reflectance, artificial rock was prepared using silica and a calcined blend of limestone and clay with various proportions of thermally immature vitrinite-rich Wyodak-Anderson coal and liptinite-rich kerogen isolated from the oil-prone Parachute Creek Member of the Green River Formation. The samples were subjected to hydrous pyrolysis for 72 h. at isothermal temperatures of 300 °C, 330 °C, and 350 °C to simulate burial maturation. Compared to artificial rock that contains only coal, samples with different proportions of oil-prone kerogen show distinct suppression of calibrated Ro at 300 °C and 330 °C. The reflectance of solid bitumen generated during heating of the samples is lower than that of the associated vitrinite and does not interfere with the Ro measurements. These results provide the first experimental evidence that Ro suppression occurs in vitrinite mixed with liptinite-rich kerogen in a rock matrix. Although the precise chemical mechanism for Ro suppression by liptinite remains unclear, free radicals generated from solid bitumen and associated volatile products during maturation of liptinite may contribute to termination reactions that slow the aromatization and rearrangement of polyaromatic sheets in vitrinite, thus suppressing Ro. This mechanism does not preclude Ro suppression that might result from overpressure or differences in redox conditions during diagenesis.

Effect of formation overpressure on the reservoir diagenesis and its petroleum geological significance for the DF11 block of the Yinggehai Basin, the South China Sea

Abstract Overpressure is an essential factor that controls the accumulation and distribution of oil and gas. In this study, we systematically studied the effects of overpressured fluid activities on the diagenesis and diagenetic evolution of reservoirs in the DF11 Block of the Yinggehai Basin, the South China Sea. The employed methods included thin-section observation, scanning electron microscopy, geochemical analysis of formation water, and C-O isotopic study. The formation water in the DF11 Block was classified as NaHCO3-type continental sedimentary water, showing high HCO3− content and extremely low concentrations of Ca2+ and Mg2+. The formation overpressure drove the carbonate ion-bearing thermal fluid flowing into the top boundary of the overpressure. The carbonates ions were re-precipitated from the fluid due to decreasing pressure and temperature. As a result, a tightly plugged zone that consisted of high carbonate cement content was formed. On the other hand, the overpressure reduced the sources of carbonate cement and limited the secondary growth of quartz by inhibiting the transformation of clay minerals. Consequently, the primary pores in the reservoir were largely preserved. Furthermore, the overpressure increased the solubility of CO2 and generated a large amount of H+ ions in the CO2-rich reservoir, which promoted the dissolution of feldspar and cements in the reservoir. The formation overpressure restrained the mechanical compaction, enhanced the dissolution of minerals, and restricted the cement production, all of which facilitated the formation of high-porosity and mid-depth overpressure reservoirs in the DF11 Block.

Increased likelihood of induced seismicity in highly overpressured shale formations

SUMMARYFluid-injection processes such as disposal of saltwater or hydraulic fracturing can induce earthquakes by increasing pore pressure and/or shear stress on faults. Natural processes, including transformation of organic material (kerogen) into hydrocarbon and cracking to produce gas, can similarly cause fluid overpressure. Here, we document two examples from the Western Canada Sedimentary Basin where earthquakes induced by hydraulic fracturing are strongly clustered within areas characterized by pore-pressure gradient in excess of 15 kPa m−1. Despite extensive hydraulic-fracturing activity associated with resource development, induced earthquakes are virtually absent in the Montney and Duvernay Formations elsewhere. Statistical analysis suggests a negligible probability that this spatial correlation developed by chance. This implies that, in addition to known factors such as anthropogenic pore-pressure increase and proximity to critically stressed faults, high in situ overpressure of shale formations may also represent a controlling factor for inducing earthquakes by hydraulic fracturing. On a geological timescale, natural pore-pressure generation may lead to fault-slip episodes that regulate the magnitude of formation overpressure.

Active Seafloor Seepage Along Hydraulic Fractures Connected to Lateral Stress From Salt‐Related Rafting: Regab Pockmark, Congo Fan

AbstractSeafloor seepage is a widespread phenomenon within salt‐influenced basins as the deformation provides pathways for hydrocarbons to reach the seafloor. However, only minor attention has been given to the distal parts of such systems where the impact of salt tectonic deformation is relatively unpronounced. The stress put on the sedimentary column by moving salt on a continental margin may influence fluid flow systems even outside of the salt province. This stress may lead to overpressure formation within reservoirs and determine the orientation of overpressure‐induced fractures. Seepage in the Congo Fan has been discovered in such a distal position at the Regab pockmark, about 35 km west of the salt front, and its geology and biology have been studied extensively in recent years. We present high‐resolution multichannel seismic data from the Regab pockmark that reveal the underlying migration pathways from a buried channel flank 300 m below seafloor to the seafloor via hydraulic fractures in the sealing overburden. Local doming of the reservoir and the remobilization and uplift of sedimentary strata along the migration pathways are interpreted as the result of overpressure within the reservoir. The orientation of the hydraulic fractures is WSW‐ENE, and the fracture outline corresponds to the area of most intense seepage activity within the seafloor pockmark. Along with a similar orientation of other fractures in the vicinity, we propose that this alignment is due to the stress imposed on the sedimentary column in the fan by the seaward moving salt and rafting sedimentary packages of the salt province further east.

Formation mechanisms of good-quality clastic reservoirs in deep formations in rifted basins: A case study of Raoyang sag in Bohai Bay Basin, East China

Abstract In order to reveal the development mechanism of high-quality clastic rock reservoir, the basic characteristics of Sha-3 Member of the Shahejie Formation in the Raoyang sag, Bohai Bay Basin, are analyzed based on cores observation, thin-sections and SEM images, and petrophysical properties measurements as well. It is found that high-mature composition and texture, early oil charging, and dissolution are the main factors controlling the formation and preservation of pores in deep reservoirs. Compaction is the major factor destructing pores, whereas formation overpressure is conducive to the preservation of original pores, high compositional and medium textural maturity can enhance the resistance capacity to compaction and protect primary pores. Early oil charging could lead to temporary cessation of diagenesis and thus inhibit the cementation. When organic acids entered reservoir formations, considerable amounts of secondary pores were formed, leading to the local improvement of petrophysical properties. When predicting good quality belt in exploration of deep basin, it is recommended that the superimposing effects of the multiple factors (overpressure, early oil charging, compositional and textural maturity, diagenesis) be taken into consideration.

Advances in the origin of overpressures in sedimentary basins

Much progress in the studies on overpressuring mechanisms has been made during the past one to two decades. (1) The causes of overpressure are divided into five categories, namely, disequilibrium compaction, fluid expansion, diagenesis, tectonic compression and pressure transfer. The fluid expansion involves hydrocarbon generation, oil cracking to gas and hydrothermal expansion. The diagenesis includes smectite-to-illite transformation. (2) Six methods for identifying overpressure origin are proposed, including log curves combination analysis, Bowers method (loading-unloading diagram), velocity-density crossplotting, correlation of porosities, pressure calculation and correlation, and comprehensive analyses. (3) With more and more application of empirical methods in the study of overpressure formation, almost all of the overpressure cases that are traditionally thought to be caused by disequilibrium compaction are denied totally or partly. Instead, the hydrocarbon generation is demonstrated to be the most significant mechanism for overpressure formation; the clay diagenesis (especially the smectite-illite transformation) as well as tectonic compression and pressure transfer are also important for overpressure formation. In addition, the overpressure formation in many basins is thought to be influenced by the combination of two or more overpressuring mechanisms. (4) Causes of overpressuring differ in lithology; for mudstones, the overpressure formation in source rocks is usually different from that of non-source rocks, the former of which is frequently related to hydrocarbon generation and sometimes also affected by diagenesis, while the later of which is commonly related to disequilibrium compaction, diagenesis and pressure transfer; for permeable rocks such as sandstones, overpressure is mainly caused by pressure transfer. (5) Because organic matter has an obvious influence on logging parameters such as density and acoustic velocity, an appropriate correction on the content of organic matter is needed when these logging data are used to analyze overpressure formation in organic-rich mudstones. It has been revealed that the cause of overpressuring based on the corrected log data can be quite different from that without correction.

Genetic mechanisms and distribution characteristics of overpressures in the Paleogene reservoirs of the Bohai Bay Basin, East China

The Bohai Bay region is a primary accumulation area of oil and gas in offshore China, in which overpressure commonly occurs in the Paleogene strata; the analysis on distribution characteristics and genetic mechanisms of the overpressure would provide geologic evidences for making plans of well drilling and logging as well as oil and gas exploitation; additionally, it could lay the geological foundation for studying how overpressure controlled hydrocarbon accumulation. Based on research, the overpressure of the study area starts from the second member of the Dongying Formation and ends in the third member of the Shahejie Formation. The distribution of overpressure is mainly controlled by the sag–salient tectonic framework within the basin, which means overpressure mainly develops in sags or slopes; however, high areas stay normal pressured. In the study area, pressure develops around Bozhong Sag and in northern Liaodong Bay reaches the peak. The genetic mechanisms of overpressures in the Paleogene reservoirs are mainly disequilibrium compaction, hydrocarbon generation of the organic matter, fluid charging, and transmission or the superimposition of the former two. Different strata have different genetic mechanisms of overpressure. The chief genetic mechanisms for the generation of overpressure of the Dongying Formation are disequilibrium compaction while the genesis of the formation of overpressure in the Shahejie Formation is more complicated in some extent. The first member of the Shahejie Formation dominated by disequilibrium compaction and hydrocarbon generation of the organic matter plays a supplemental role, while the second member of the Shahejie Formation, as the primary reservoir strata, is dominated by fluid charging and transmission, and the third member of the Shahejie Formation is the main source rock interval; its overpressure is closely related to hydrocarbon generation. Each contribution ratio for overpressure forming by different genetic mechanisms has been judged and figured out quantitatively according to geological, geophysical, and geochemical characteristics of the target strata.

Disequilibrium compaction overpressure in shales of the Bavarian Foreland Molasse Basin: Results and geographical distribution from velocity-based analyses

Abstract Shale velocity data from sonic logs and vertical seismic profiles, drilling data and in situ pressure measurements from a total of 116 wells have been analyzed to gain an improved understanding of the lateral and vertical distribution and formation of overpressure in the Bavarian Foreland Molasse Basin. Pore pressure from sonic and vertical seismic profile velocities has been analyzed by establishing a normal compaction trend for Cenozoic and Mesozoic shales combined with a classical Eaton approach. The study demonstrates that a single shale normal compaction trend for the Bavarian Foreland Molasse Basin is sufficient to estimate pore pressure and thus overpressure from sonic and vertical seismic profile velocity. Maximum overpressure develops at depths between 1500 and 2500 m and increases with depth at a constant effective stress of 20 MPa. The strong dependency of overpressure on burial depth, constant effective stress and restriction to shale units that are overlain by sequences with very high sedimentation rates indicates that disequilibrium compaction is the main cause for overpressure. Also, variable presence of Cretaceous shales is a key control of overpressure occurrence in Oligocene shales in the Bavarian Foreland Molasse Basin, since Cretaceous shales likely act as a “pressure buffer” to underpressured Mesozoic carbonates. Successful detection and prediction of overpressure from vertical seismic profile data is encouraging for future pre-drill prediction of overpressure from velocity data of seismic surveys in the Bavarian Foreland Molasse Basin, resulting in improved well planning, reliable calculation of project costs, and improved safety during drilling activities in the Bavarian Foreland Molasse Basin. The presented overpressure distributions will be a key input for future geomechanical, basin and reservoir modelling studies in the Bavarian Foreland Molasse Basin.

Numerical simulation of water and sand blowouts when penetrating through shallow water flow formations in deep water drilling

In this study, we applied a two-phase flow model to simulate water and sand blowout processes when penetrating shallow water flow (SWF) formations during deepwater drilling. We define ‘sand’ as a pseudo-component with high density and viscosity, which can begin to flow with water when a critical pressure difference is attained. We calculated the water and sand blowout rates and analyzed the influencing factors from them, including overpressure of the SWF formation, as well as its zone size, porosity and permeability, and drilling speed (penetration rate). The obtained data can be used for the quantitative assessment of the potential severity of SWF hazards. The results indicate that overpressure of the SWF formation and its zone size have significant effects on SWF blowout. A 10% increase in the SWF formation overpressure can result in a more than 90% increase in the cumulative water blowout and a 150% increase in the sand blowout when a typical SWF sediment is drilled. Along with the conventional methods of well flow and pressure control, chemical plugging, and the application of multi-layer casing, water and sand blowouts can be effectively reduced by increasing the penetration rate. As such, increasing the penetration rate can be a useful measure for controlling SWF hazards during deepwater drilling.

Pressure field characteristics of petroliferous sags in Bohai Bay Basin: Implication for hydrocarbon enrichment

Pressure fields of different sags in a petroliferous basin were significantly different, and it was related to hydrocarbon enrichment. Based on pressure data of different sags in Bohai Bay Basin, types of pressure field and its distribution characteristics were well discussed, and relationships between overpressure and hydrocarbon generation, pressure field and hydrocarbon enrichment were also investigated. Results showed that the Paleogene pressure fields of different sags in Bohai Bay Basin could be divided into three types: normal pressure type, single overpressure type and double overpressure type. These three types of pressure fields had the zoned features in their distributions. The normal pressure fields were mostly distributed in peripheral sags of the basin, while the single overpressure fields were widespread in the basin, and the double overpressure fields were concentrated in the areas around the Bohai Sea. Hydrocarbon generation had a significant effect on overpressure formation, thus overpressure horizons generally were corresponded to major source rock horizons, and differences of filling evolution history and main hydrocarbon-generation strata of different sags might be important factors for the formation of these three types of pressure fields. Overpressure in source rock horizons was closely related to hydrocarbon enrichment. Horizontally, hydrocarbons were mainly distributed around the overpressure center, and the secondary migration distance of hydrocarbons was affected by the degree of overpressure. Vertically, hydrocarbon distribution was controlled by the type of pressure fields. Hydrocarbons in the normal pressure sags were mainly enriched in the major hydrocarbon-generation horizons and their adjacent horizons, hydrocarbons in the single overpressure sags were mainly distributed in the hydrocarbon-generation horizons and its upper and lower horizons, while in the double overpressure sags, the hydrocarbon enrichment degree in Neogene was high. Hydrocarbon enrichment in sags was controlled by the degree of overpressure in hydrocarbon-generation horizons, and these oil-rich sags had relatively large overpressure degree.

Geothermometry and geobarometry of overpressured lower Paleozoic gas shales in the Jiaoshiba field, Central China: Insight from fluid inclusions in fracture cements

The Wufeng-Longmaxi organic-rich shales host the largest shale gas fields of China. This study examines sealed fractures within core samples of the Wufeng-Longmaxi shales in the Jiaoshiba shale gas field in order to understand the development of overpressures (in terms of magnitude, timing and burial) in Wufeng-Longmaxi shales and thus the causes of present-day overpressure in these Paleozoic shale formations as well as in all gas shales. Quartz and calcite fracture cements from the Wufeng-Longmaxi shale intervals in four wells at depth intervals between 2253.89 m and 3046.60 m were investigated, and the fluid composition, temperature, and pressure during natural fracture cementation determined using an integrated approach consisting of petrography, Raman spectroscopy and microthermometry. Many crystals in fracture cements were found to contain methane inclusions only, and aqueous two-phase inclusions were consistently observed alongside methane inclusions in all cement samples, indicating that fluid inclusions trapped during fracture cementation are saturated with a methane hydrocarbon fluid. Homogenization temperatures of methane-saturated aqueous inclusions provide trends in trapping temperatures that Th values concentrate in the range of 198.5 °C–229.9 °C, 196.2 °C-221.7 °C for quartz and calcite, respectively. Pore-fluid pressures of 91.8–139.4 MPa for methane inclusions, calculated using the Raman shift of C-H symmetric stretching (v1) band of methane and equations of state for supercritical methane, indicate fluid inclusions trapped at near-lithostatic pressures. High trapping temperature and overpressure conditions in fluid inclusions represent a state of temperature and overpressure of Wufeng-Longmaxi shales at maximum burial and the early stage of the Yanshanian uplift, which can provide a key evidence for understanding the formation and evolution of overpressure. Our results demonstrate that the main cause of present-day overpressure in shale gas deposits is actually the preservation of moderate-high overpressure developed as a result of gas generation at maximum burial depths.

Three-Dimensional Pressure Modeling of South China Sea in High Temperature High Pressure Field

Yingqiong basin is a proven hydrocarbon-rich basin in South China Sea. There are a number of large exploration prospects in high temperature and over-pressured formations, especially in Yacheng Block of Qiongdongnan basin and Dongfang District of Yinggehai Basin. Owing to good exploration situation, we have already achieved proven geological reserves over 1000 × 108 m3. In recent years, a few drilled HPHT wells have confirmed that pressure predicted by conventional method was wildly inaccurate. From the view of regional stress, the accuracy of the pressure prediction will be substantially improved. Accurate pressure prediction and three-dimensional pressure modeling which are based on three-dimensional lithology modeling are the cornerstone to achieve exploration breakthrough. In this paper, the use of the triple constraint trend lithology model broke through the traditional method of seismic lithology prediction only by means of impedance threshold value. Compared with actual data and prediction, it confirms that three-dimensional pressure modeling method is reasonable and effective, and has a wide prospect of application.

Q Versatile Seismic Imager (QVSI) Successfully Predicts Target Depth and Pore-Pressure in HPHT Environment

Drilling in any environment is challenging as it poses a challenge to drill reservoir targets without losses and minimum casing strings and is even challenging in HPHT (high pressure high temperature) environment. Seismic is the fundamental for pre-drill prognosis and completion design. The target depth prognosis is achieved through depth transformation by using seismic velocities or available velocity logs in the nearby field or block and often has varying degree of uncertainty in target depths depending upon the suitable of the velocity function used. The velocity function used could be affected due to available seismic bandwidth or structure. These uncertainties in target depths often lead to increased well costs as a result of wellbore stability issues & undesired casing strings. Most common issue faced by drillers is the target confirmation & distance to these targets ahead of bit. Vertical seismic profile (VSP) look-ahead at intermediate depths is one of the approaches to mitigate these uncertainties and drill wells safely. VSP help confirm the presence of drilling targets & also predict the depth to top of these targets. Additionally, the predicted interval velocity is used to predict the pre-pressure for next section drilling. In South China Sea, oil & gas operators face a significant risk while drilling over-pressured formations. It is therefore imperative to know the depth to top of these high pressured formations to avoid drilling directly into it and risking the well. It is also important to know the pore-pressure and mud weight for the next section to be drilled for safe drilling & with minimum casing strings [1] [2] [3]. It is more difficult to get this information in the HPHT environment due to the lack of high temperature tools [4]. Schlumberger’s proprietary QVSI*—High pressure, high temperature VSI* (Versatile Seismic Imager) has been successfully used to predict the target depth for casing landing and pore-pressure prediction in HPHT environment. QVSI is the latest generation of VSI* Versatile Seismic Imager tools developed by Schlumberger to acquire high quality tri-axial borehole seismic data in extreme environment wells. The QVSI* tool uses the Q-Technology* singlesensor hardware and software and advanced wireline telemetry for fast digital seismic data transmission from borehole to surface. QVSI is a high-temperature, high-pressure array tool design that focuses on tri-axial vector fidelity and efficient data acquisition, extending the limits in a 4-tool configuration to 500°F (260℃) and 30 kpsi (207 MPa). In this paper, a case study is presented for Well-XX for CNOOC from South China Sea. The well-xx is located in Yanyan Sag, Qiongdongnan Basin and the downhole temperature was 204℃. The main target layer is Lingshui III sandstone, which is controlled by Northwest fault. It is a gas well and critical for the client to land the casing at right depth and know the drilling parameters for the next section ahead. QVSI* predicted the target depth within ±2 m for decision on casing point. The predicted pore pressure was within ±0.1 ppg.

The axial channel provenance system and natural gas accumulation of the Upper Miocene Huangliu Formation in Qiongdongnan Basin, South China Sea

Abstract Based on the data of regional outcrop observation, high-precision 3-D seismic detection and wellbore rock-electricity, this paper researched macro-water distribution, seismic architecture of sedimentary-filling, rock composition, heavy mineral assemblage, and zircon age. The axial channel provenance system and accumulation of natural gas of the Upper Miocene Huangliu Formation in the Qiongdongnan Basin was analyzed. The research showed that axial channels deposits were provided with two depression stages, multiple provenances, and gravity flows by bottom current rework. Early channels sandstone with small size and formation overpressure was mainly from terrigenous material of southwest drainage system in Hainan uplift, while Qiupen River in the central Kunsong uplift was the primary provenance of late channels sandstone with large scale of sediments, good continuity and normal formation pressure. There are three types of axial channel sandstone traps: litho-stratigraphic, lithologic and tectono-stratigraphic trap. Natural gas of early channels was driven by deep overpressure and vertically migrated into reservoir along fissures, while natural gas of late channels lateral migrated from west to east.

Hydrocarbon migration caused by rupture of pressure compartment in south Liaozhong sag, Bohai Bay Basin, Offshore China

Abstract Based on the study of the abnormal pressure of mudstone and reservoirs of south Liaozhong sag, Bohai Bay Basin, the structure of the abnormal pressure compartment in the Paleogene of south Liaozhong sag and its impact on oil and gas migration have been analyzed. The pressure compartment in the study area has a “sandwich structure”, with the mudstone of Paleogene Dongying Formation as cap rock, the reservoirs of the upper Shahejie Formation of the Paleogene as the transport interlayers, and the mudstone from the lower Shahejie Formation as the hydrocarbon source rock. Based on overpressure formation mechanism and basin-modeling, the pre-neotectonic movement pressure of the transport interlayers was reconstructed, then the rupture of the pressure compartment and pressure differentiation caused by Tanlu fault zone during the neo-tectonic movement were investigated. The hydrocarbon migration was simulated under different pressure conditions before and after the neo-tectonic movement, to find out the relationship between the neo-tectonic movement of Tanlu fault, abnormal pressure and oil and gas migration. The simulation results show that the differential activity within Tanlu fault zone caused the differentiation of pressure and increase of fluid potential gradient; and the strike-slip pull-apart area with low potential caused by pump-sucking effect became the main direction of hydrocarbon migration in Tanlu fault zone. The comprehensive research of the late-stage hydrocarbon accumulation shows that, there are inner and outer compartment hydrocarbon accumulation systems in the south Liaodong sag, and the transport interlayer in the inner compartment is the “hydrocarbon transfer station” of the shallow outer compartment, and determines the hydrocarbon plane distribution.

COMSOL Multiphysics Modeling of Architected Acoustic Transducers in Oil Drilling

ABSTRACTIn the oil and gas industry, acoustic transducers have been found to provide valuable geological sonic information such as compressional wave velocity, shear wave velocity, and rock formation slowness. These data can be used to indicate lithology, determine porosity, detect over-pressured formation zones, and check well to well correlation. One category of such acoustic transducers is equipped with piezoelectric elements. Conventional piezoelectric transducers are packaged by epoxy resin. Because of the liquid nature of uncured epoxy resin, it is difficult to position the piezoelectric elements accurately. The introduction of polyether ether ketone (PEEK) as the packaging material solved this issue. Due to the ease of machining on solid form, architectures of the composite acoustic transducers can be devised with great flexibility and creativity. These designs can be modeled with finite element methods (FEM) and the best design for the oil drilling application can be finalized and fabricated.COMSOL Multiphysics® solves problems in a programming environment that integrates relevant physics. In this case, it includes electrical circuit, solid mechanics, acoustics, and piezoelectricity. Here a compete model and procedure to study the performance of an architected composite acoustic transducer is provided. The displacement analysis gives insights into the resonance modes of the piezoelectric elements. The acoustics analysis gives the necessary information on the acoustic performance of the transducers, such as acoustic pressure spatial distribution, acoustic pressure frequency response, transmitting voltage response, and directivity. These are important criteria to judge the effectiveness of an architected transducer.