Top Of Reservoir Research Articles

Origin of Basaltic Subplinian Eruption at Shishaldin Volcano (Alaska): A Vigorously Degassing Magma Reservoir Hosting Small Bubbles

AbstractThe 1999 basaltic eruption of Shishaldin volcano (Alaska) displayed a transition between Subplinian and Strombolian activity. Strombolian bubbles indicate the presence of a periodically unstable foam at the top of magma reservoir. In contrast, a long foam, whose rupture led to the eruptive column, was also able to collect in the conduit. Laboratory experiments show that long foams can be produced in a conduit by the spreading of a stable foam accumulated at the top of the reservoir. The existence of a Taylor bubble at the onset of the Subplinian phase, also reproduced by my laboratory experiments, suggests that the foam in the reservoir was just at the transition between stable and unstable. This constrains the bubble diameter prior to the Subplinian phase to be 0.034–0.038 mm when using the foam dimensionless analysis and the underlying gas flux (0.52–0.80 m3/s). The increase in bubble diameter and potentially gas flux prior to the Strombolian activity, 0.81–1.4 m3/s, is sufficient to explain the foam in transition to be unstable. The radius of the magma reservoir is small, 200–210 m, as expected. The bubble diameter is the smallest of those estimated for classical basaltic eruptions (Etna, Kı̄lauea, Erta 'Ale), while the gas flux is among the largest. A dilute suspension of small and isolated bubbles cannot explain the large gas flux at Shishaldin. This implies numerous bubbles with a gas volume fraction ≥0.63−2%, a regime for which the bubbles form bubble clusters. The diameter of these bubble clusters, 3.0–5.4 mm, is sufficient to explain large gas fluxes.

Seismic net-to-gross estimation for a geologic model update: A case study from a turbidite lobe reservoir in the deepwater of the Niger Delta

Geologic model updates are routinely performed in mature fields to obtain improved descriptions of facies distributions and reservoir properties such as volume of shale, net to gross (NTG), and porosity, for better understanding of the static and dynamic behaviors of reservoirs for effective well placement, improved production, and monitoring. A simple but integrated seismic NTG estimation approach, using detuned seismic amplitudes is used in guiding NTG modeling during the geologic model update of a thin turbidite lobe reservoir in a mature oil field in the deep offshore Niger Delta. The objective is to address NTG overestimation and gross rock volume (GRV) uncertainty in a previous model arising from seismic amplitude tuning effects. A seismic NTG approach is chosen relative to sophisticated deterministic or stochastic inversion techniques to avoid tuning effects, which usually bias NTG estimates in thin turbidite reservoirs. The primary data set is a 2019 reprocessed prestack depth-migrated (PSDM) seismic data vintage, which had better resolution, higher signal-to-noise ratio, and more appropriate angle-stack apertures for amplitude variation with angle fidelity, than the older 2011 PSDM seismic data that are used in the previous geologic model. The methodology involved rock-physics analysis, seismic data quality checks (QCs), tuned area determination, detuning of composite seismic amplitudes of the top and base reservoir, and their direct calibration to NTG at wells. Good correlations are obtained between the detuned composite seismic amplitudes and NTG at wells. The seismic NTG map shows good calibrations at wells and provides a robust trend for net sand modeling in the oil pool and aquifer. Static model QCs and dynamic simulations prove that the seismic NTG attribute addressed the GRV uncertainty in the earlier model, thus giving confidence for using the updated model for the planning and geosteering of infill wells, sand completions, reservoir monitoring, and production.

Seismic wave modeling of fluid-saturated fractured porous rock: including fluid pressure diffusion effects of discretely distributed large-scale fractures

Abstract. The scattered seismic waves of fractured porous rock are strongly affected by the wave-induced fluid pressure diffusion effects between the compliant fractures and the stiffer embedding background. To include these poroelastic effects in seismic modeling, we develop a numerical scheme for discretely distributed large-scale fractures embedded in fluid-saturated porous rock. Using Coates and Schoenberg's local-effective-medium theory and Barbosa's dynamic linear slip model characterized by complex-valued and frequency-dependent fracture compliances, we derive the effective viscoelastic compliances in each spatial discretized cell by superimposing the compliances of the background and the fractures. The effective governing equations for fractured porous rocks are viscoelastic anisotropic and numerically solved by the mixed-grid-stencil frequency-domain finite-difference method. The main advantage of our proposed modeling scheme over poroelastic modeling schemes is that the fractured domain can be modeled using a viscoelastic solid, while the rest of the domain can be modeled using an elastic solid. We have tested the modeling scheme in a single fracture model, a fractured model, and a modified Marmousi model. The good consistency between the scattered waves off a single horizontal fracture calculated using our proposed scheme and the poroelastic modeling validates that our modeling scheme can properly capture the fluid pressure diffusion (FPD) effects. In the case of a set of aligned fractures, the scattered waves from the top and bottom of the fractured reservoir are strongly influenced by the FPD effects, and the reflected waves from the underlying formation can retain the relevant attenuation and dispersion information. The proposed numerical modeling scheme can also be used to improve migration quality and the estimation of fracture mechanical characteristics in inversion.

Reservoir top detection by resistivity logging signals in deviated and horizontal wells: comparative analysis

This research is aimed at finding out the capabilities of an electromagnetic probe with toroidal coils in geosteering problems. Three-dimensional numerical finite-difference modeling of electromagnetic responses was performed for a probe with toroidal coils, for high-frequency electromagnetic logging probe and side logging sondes in two-layer models with varying resistivity contrast and borehole zenith angle. Based on these calculations, the key features of the toroidal coil electromagnetic sounder (ZET), high-frequency electromagnetic logging (VIKIZ) and side logging (BKZ) signals in detecting the boundary before it is crossed are shown. These features make it possible to determine the approach to the roof of the collector using the signals ZET, VIKIZ and BKZ.

Heat extraction performance analysis of a multilateral wells exploitation system with super-long gravity heat pipe

Super-long gravity heat pipe (SLGHP) system has previously been proven as an environmental and efficient technology in exploiting hot dry rock. This study proposed a multilateral-well SLGHP system to achieve the purposes of improving heat extraction performance and fully utilizing fractured reservoirs. The heat extraction performance was investigated by establishing a 3D thermal–hydrologic (TH) coupling model. It is found that, compared to traditional single-well SLGHP system, after 30 years of operation, multilateral-well SLGHP system has improved the heat extraction rate by 38.1 kW and increased the heat compensation by 61×1012 J. The utilization ratio of geothermal reservoirs has been improved by 8.1%. In addition, the effects of different well layouts on heat extraction performance are also studied. Injection wells at the top of fractured reservoir increase the heat extraction rate by 6.4 kW compared to placing them in the bottom area. The relative changes of wellbore location in fractured reservoirs have slight effects on heat extraction performance. This study could provide good suggestions for the SLGHP system to obtain better heat extraction performance.

STRUCTURE AND LITHO-FACIAL FEATURES OF THE QALA SUITE DEPOSITS OF THE ZYKH-HOVSAN AREA ACCORDING TO 3D SEISMIC AND WELL LOGGING DATA

Background. A detailed study of the geological structure and litho-facial features of the deposits of the Pliocene productive series based on 3D seismic and Well Logging data is of great practical importance, as the main share of hydrocarbons produced in Azerbaijan occurs in these deposits. The purpose of the research was to identify the features of the geological structure of the Zykh-Hovsan area, study the litho-facial properties deposits of the Qala Suite of the productive series, identify and study the deposits within the 3 formations of the Qala Suite based on a joint analysis of 3D seismic and Well Logging (WL) data. Methods. Structural mapping based on seismic data was chosen as the main research method. In studying the Qala part of the section, seismogeological, seismostratigraphic and paleogeomorphological analyzes were also carried out. Results. According to the contour of anomalies of lowered and enhanced values of medium amplitudes (reflected waves) RW of the SH (seismic horizons) and maps of temporary thicknesses, and in some cases along faults, in different parts of the Zykh-Hovsan area within the QaS formations, deposits were identified, their size and area were determined. Effective and oil saturated thicknesses were determined for each deposit. According to the last interval of testing and perforation in the wells drilled in the study area, as well as along the top of the water-saturated reservoir and along the bottom of the oil-saturated reservoir, absolute marks (a.m.) of oil-water contacts of the identified deposits were established. The nature of saturation was determined using WL data. The type of each deposit was also determined in the process of research. Conclusions. In Qala deposits developed in the research area, the following were identified: one perspective trap in the QaS-3 formation, two traps in the QaS-2 formation and one trap in the QaS-1 formation at the Zykh field, which were identified on the basis of paleo-geomorphological features where it is suspected that the conditions for accumulation of sandy material are advantageous.

A workflow for turbidite reservoir characterization—a case study of the Macedon member, Northern Carnarvon Basin, NW Australia

Deep-water turbidite systems on passive continental margins are of interest for oil and gas exploration. However, their complexity poses challenges for reservoir characterization. In this study, we proposed a reservoir characterization workflow for the Macedon member turbidite, employing a combination of 90° phase adjustment, geobody extraction, and genetic inversion, based on the abundant well logging and seismic data from the Enfield field, Northern Carnarvon Basin. Our workflow involved seismic sedimentology to determine the morphology of sand bodies and inversion to determine the net reservoir range, resulting in 3D geological attribute modeling. We applied a 90° phase adjustment correlated seismic events and well logging responses. By stratal slice interpretation and geological body extraction, it was revealed the turbidite reservoir distribution. Finally, we achieved net reservoir characterization of the Macedon member through genetic inversion porosity and geostatistical methods. The results showed that the Macedon turbidite reservoir can be divided into the top and base reservoirs. The top reservoir is sheet-like, and the base reservoir is channelized. The average porosity of the former was 24%, while the average porosity of the later is 20%. The top reservoir has better reservoir quality. Furthermore, we discussed sea level changes affect turbidite distribution and reservoir quality. During the Falling Stage Systems Tract (FSST), the long transportation distance led to relatively less sediment supply and a low sand/mud ratio, resulting in confined, channelized, poor quality turbidite reservoir. In contrast, during the Lowstand Systems Tract (LST), unconfined, amalgamated, good quality turbidite sheet reservoirs were formed. The improved workflow based on seismic sedimentology presented in this article proves effective in characterizing complex reservoirs and contributes to the simplified and efficient management of reservoirs.

Geological characteristics and main controlling factors of the helium-rich gas reservoirs in Sozak Gas Field, Kazakhstan

Based on core data, physical properties, well logging, gas testing, composition, and helium distribution from 13 newly drilled wells, in combination with regional tectonic evolution, depositional background, and typical gas reservoir profiles, helium-rich gas reservoirs geology characteristics and main controlling factors have been explored. The results show that three gas reservoirs formed from bottom to top, i.e., granite and metamorphite fractured reservoir in the basement, tight sandstone structural reservoirs in the Devonian, and huge continuous carbonate reservoirs in the Lower Carboniferous. Fractures developed on structural points control high-production, and gas is prominently displayed in low structural areas. The dry gas exhibits richness in helium, with decreasing helium content from the basement to the Carboniferous. The pre-Devonian large-scale granite and metamorphite basement serve as the primary helium source, while the high-gamma sandstones of the Devonian and the Carboniferous act as secondary sources. Fractures play a dual role, being filled up and conducting in two ways: gas from the Carboniferous source rocks migrates downward, and helium migrate upward. Thick interbedded gypsum-tight limestone on top of the Lower Carboniferous act as the regional caprock, effectively preserving the helium-rich gas reservoirs.

An experimental study on horizontal well waterflooding in the Cretaceous porous carbonate reservoir of Oman

Porous carbonate reservoirs, prevalent in the Middle East, are lithologically dominated by bioclastic limestones, exhibiting high porosity, low permeability, intricate pore structure, and strong heterogeneity. Waterflooding through horizontal wells is commonly used for exploiting these reservoirs. However, challenges persist, such as significant uncertainty and complex operational procedures regarding adjustment effects during the exploitation. The USH reservoir of the Cretaceous D oilfield, Oman exemplifies typical porous carbonate reservoirs. It initially underwent depletion drive using vertical wells, followed by horizontal well waterflooding in the late stage. Currently, the oilfield is confronted with substantial developmental challenges, involving the understanding of residual oil distribution, effective water cut control, and sustaining oil production since it has entered the late development stage. Employing a microscopic visualization displacement system equipped with electrodes, this study elucidated the waterflooding mechanisms and residual oil distribution in the late-stage development of the USH reservoir. The results reveal that the reservoir's vertical stacking patterns act as the main factor affecting the horizontal well waterflooding efficacy. Distinct water flow channels emerge under varying reservoir stacking patterns, with post-waterflooding residual oil predominantly distributed at the reservoir's top and bottom. The oil recovery can be enhanced by adjusting the waterflooding's flow line and intensity. The findings of this study will provide theoretical insights of waterflooding mechanisms and injection-production adjustments for exploiting other porous carbonate reservoirs in the Middle East through horizontal wells.

Study on acoustic properties of hydrate-bearing sediments with reconstructed CO2 hydrate in different layers during CH4 hydrate mining

Natural gas hydrate (NGH), a clean energy source with huge reserves in nature, and its safe and efficient exploitation fits perfectly with the UN Sustainable Development Goals (SDG-7). However, large-scale NGH decomposition frequently results in subsea landslides, reservoir subsidence, and collapse. In this work, in order to achieve safe and efficient exploitation of NGHs, the stability variation of different reservoir layers by depressurization/intermittent CO2/N2 injection (80:20 mol%, 50:50 mol%) was investigated using acoustic properties (P-wave velocity, elastic modulus), as well as reservoir subsidence under an overburden stress of 10 MPa. The P-wave velocity increased from 1282 m/s to 2778 m/s in the above-reservoir and from 1266 m/s to 2564 m/s in the below-reservoir, significantly increasing reservoir strength after CO2 hydrate formation. The P-wave velocity and elastic modulus in the top reconstructed reservoir were continually decreased by the shear damage of the overlying stress, while they remained stable in the bottom reconstructed reservoir during hydrate mining. However, due to superior pressure-bearing ability of the top CO2 hydrate reservoir, which was lacking in the bottom CO2 hydrate reservoir, the reservoir subsidence was relieved greatly. Despite the stiffness strength of reconstructed reservoir was ensured with CO2/N2 sweeping, the skeletal structure of CH4 hydrate reservoir was destroyed, and only the formation of CO2 hydrate could guarantee the stability of P-wave velocity and elastic modulus which was most beneficial to relieve reservoir subsidence. A large amount of CO2 was used in reservoir reconstruction and CH4 hydrate mining, which achieved the geological storage of CO2 (SDG-13). This work provided a new idea for safe and efficient NGHs mining in the future, and the application of acoustic properties served as a guide for the efficient construction of reconstructed reservoirs and offers credible technical assistance for safe exploitation of NGHs.

Study on the supercritical phase behavior of Yaha condensate gas reservoir in Tarim Basin

Yaha condensate gas reservoir is condensate gas reservoir developed by gas injection in the Tarim Basin. The practice of gas injection in condensate gas reservoir shows that the key to improve gas injection effect is to control gas channeling. Dynamic monitoring shows that there is no instantaneous miscibility between dry gas and condensate gas during gas injection. Based on the principle of entropy increase and mass transfer kinetics, the phase behavior of condensate gas and dry gas in reservoir is analyzed theoretically. The new technique to improve condensate recovery is adopted for condensate gas field. By using the density difference and seepage characteristics of dry gas and condensate gas, the injected dry gas cap is formed at the top of the gas reservoir, and the three-dimensional displacement is realized by the expansion of dry gas cap. Gas injection gravity assisted flooding technology is to realize vertical displacement of injected gas through the expansion of dry gas cap by using gravity differentiation caused by gas density difference. This technology can keep the front edge of gas injection advance evenly and solve the problem of gas channeling in the process of cyclic gas injection.

The Messinian reservoir in El-Tamad oil field, Nile Delta, Egypt: Seismic interpretation and 3D modeling

El-Tamad Field, the first oil discovery in the onshore Nile Delta, is one of the promising areas in the Nile Delta for oil and gas. Therefore, thirty seismic lines, core data, and real-time flowline resistivity measurements of the Messinian Qawasim Formation were analyzed to characterize and model the reservoir in El-Tamad Field. The structure model shows that there are three main faults in the investigated area; F1 fault is a major growth fault trending E-W with a downthrown to the north, F2 trending NW-SE with a downthrown northeast, and the NE-SW trending F3 fault with a downthrown southeast. The depth-structure contour map on the reservoir's top shows that there is a rollover anticline fold formed at the downthrown side of the major growth fault. The petrophysical model illustrates that effective porosity increases towards both of southeastern and southwestern parts, while water saturation decreases in the southeastern part of the field, and the net-to-gross increase towards the center. Penetrating more vertical and sidetrack wells along the line connecting wells 1, 3, and 4 in El-Tamad Field, especially in the crest of the anticline fold that was recorded in the area is highly recomended. The spatial variation of the reservoir quality was attributed to the depositional setting, where many branches of larger distributary channels (sand facies) accumulated within a muddy estuary (shale facies) on the front of a bay-head delta.

Evolution Law of Dominant Flow Channel and Enhanced Oil Recovery Measures for Water Flooding in Reservoirs with Partially Sealed Faults.

The presence of strongly sealed faults can divide a reservoir into complex fault blocks, while partially sealed faults can be created by farewell faults within each block, leading to more intricate fluid migration and residual oil distribution. However, oilfields often overlook these partially sealed faults, focusing instead on the entire fault block, which can impact the efficiency of the production system. In addition, the current technology struggles to quantitatively describe the evolution of the dominant flow channel (DFC) during the water-flooding process, especially in reservoirs with partially sealed faults. This limits the ability to formulate effective enhanced oil recovery measures during the high water cut stage. To address these challenges, a large-scale sand model of a reservoir with a partially sealed fault was designed, and water flooding experiments were conducted. Based on the results of these experiments, a numerical inversion model was established. By combining percolation theory and the physical concept of DFC, a new method was proposed to quantitatively characterize DFC using a standardized flow quantity parameter. The evolution law of DFC was then studied, considering the variations of volume and oil saturation of DFC, and the water control effect of different measures was evaluated. The results revealed that, during the early stage of water flooding, a vertical uniform dominant seepage zone formed near the injector. As the water was injected, DFCs from the top of the injector to the bottom of the producers gradually formed in the unoccluded area. However, DFC was only formed at the bottom in the occluded area. During water flooding, the volume of DFC in each area gradually increased and then tended to stabilize. The development of the DFC in the occluded area lagged behind due to gravity and fault occlusion, leading to the formation of an unswept area near the fault in the unoccluded area. The volume of the DFC in the occluded area was the slowest, and the volume was the smallest after stabilization. Although the volume of the DFC near the fault in the unoccluded area grew the fastest, the volume was only higher than that in the occluded area after stabilization. During the high water cut period, the remaining oil was mainly distributed in the upper part of the occluded area, the area near the unoccluded fault, and the top of the reservoir in other areas. The plugging of the lower part of the producers can increase the volume of DFC in the occluded area, and the DFC moves up throughout the entire reservoir. This improves the utilization degree of the remaining oil at the top of the entire reservoir, but the remaining oil near the fault in the unoccluded area remains inaccessible. The combination of producer conversion, drilling infill wells, and producer plugging can alter the injection-production relationship and weaken the occlusion effect of the fault. The occluded area forms a new DFC, leading to a significant increase in the recovery degree. The deployment of infill wells near the fault in the unoccluded area can effectively control the area and improve the utilization of the remaining oil.

Analysis of the effect of formation dip angle and injection pressure on the injectivity and migration of CO2 during storage

Carbon dioxide (CO2) geological storage (CGS) can help realize the plan of “Carbon Neutrality”. Injection capacity and storage safety are crucial factors in evaluating CO2 storage efficiency. Deep saline aquifers are major sites for CGS. This study focused on evaluating the CO2 injection amount, migration safety and leakage risk. A three-dimensional (3D) model of the Shenhua CO2 capture and storage (CCS) project in the Ordos Basin, China, was established to discuss the impact of injection pressure (1.3P (equal to 1.3 times the top reservoir formation hydrostatic pressure), 1.4P, and 1.5P) and formation dip angle (0°, 5°, 10°, 15°) with fault on the total CO2 injection and migration safety. Twelve schemes were designed for simulation. Based on the results, faulting provided a pathway for CO2 leakage, posing a threat to CO2 storage safety. Injection pressure and formation dip angle had significant effects on injectivity and migration during CO2 storage. The influence of the injection pressure on the CO2 injection amount was more evident than that of the dip angle, though formation dip angle had a significant impact on the CO2 migration during storage. Increasing the injection pressure and formation dip angle increased the gas and dissolved-phase CO2 migration and decreased the CO2 leakage time and storage safety. The CO2 leakage through the fault occurred after 160, 110 and 80 years in a 15° sloping formation with 1.3P, 1.4P, and 1.5P, respectively. The CO2 injection amount was the largest for the 0° formation with 1.5P. These results provide fundamental information for CO2 storage safety and capacity, suggesting that un-faulted reservoirs with smaller dip angles should be selected for CGS projects; however, larger injection pressures can result in greater injection amounts, decreasing the migration safety of CO2 during storage.

Recovery of the main fracturing direction of oil reservoirs from seismic and AVO data

In the present work, we formulate and solve an inverse problem to recover the main fracturing direction of petroleum reservoirs from seismic and AVO data. Equivalent media theory provides a starting point for modeling an equivalent anisotropic medium starting from an isotropic background with fractures. We then represent the equivalent medium in a new coordinate system whose x-axis is parallel to the reservoir's top. Using the classical theory of wave propagation and the Invariant Embedding technique (specially to deal with anisotropic media), we solve exactly the elastodynamic equations of motion to compute the reflection of P, SV, SH waves at the reservoir's top, without the need of using the so-called Zoeppritz approximation. In the inverse problem formulation, we assume that we know a priori the reservoir isotropic background elastic constants as well as the fracture system behavior, by means of its effective compliance. We then apply a metaheuristic to recover the main fracturing direction whose input data are the amplitudes of the reflected waves recorded by the geophones and the output are two Euler-angles representing the fracturing direction. We validate the methodology using noiseless synthetic data and further test its robustness using incomplete and noisy synthetic data.

Effects of fluvial sedimentary heterogeneity on CO2 geological storage: Integrating storage capacity, injectivity, distribution and CO2 phases

Fluvial system deposits often form suitable reservoirs for CO2 geological storage (CGS). These potential storage sites usually present heterogeneous fluvial architectures at multiple scales. This heterogeneity can exert varied effects on different aspects of CGS, resulting in significant storage efficiency variability. Here, we investigate the effects of variable fluvial lithofacies associations on CO2 storage, using the Puig-reig anticline in the SE Pyrenees (Spain) as a reservoir analog. To test this, we employ a multidisciplinary approach that integrates field sedimentology, reservoir modeling, and numerical simulation of CO2 injection to produce models akin to different fluvial lithofacies associations. The storage volume and injectivity of CO2 are found to decrease in reservoirs with decreasing fractions and sizes of high-permeable facies from the proximal to the medial-distal lithofacies associations. The flow barriers created by low-permeable facies can hinder the vertical migration of the CO2 plume and prevent it from reaching the reservoir top, hence reducing the direct contact between the CO2 plume and the overlying caprock. Furthermore, an optimal amount of low-permeable layers (around 30% in this study) can increase the swept area of CO2 and reduce the proportions of free CO2 phase. These aspects can collectively increase the amount of permanently trapped CO2 and reduce the leakage risks of the injected CO2. Based on the characteristics of the resulting models (i.e., storage volume, injectivity, distribution and phases of CO2), a multi-criteria decision-making method has been used to quantitatively rank the different lithofacies associations according to their suitability for CO2 storage. In this analysis, the proximal-medial fluvial lithofacies associations are assessed to be the most suitable ones because they feature low proportions of the injected CO2 reaching the reservoir top and in free phase while maintaining the high storage volume and injectivity. This study reveals that heterogeneous reservoir architectures have mixed effects on CO2 storage, and that reservoirs featuring moderately heterogeneous architectures (i.e., fractions of low-permeable facies ranging from 30% to 40%) are beneficial to keeping the balance among different aspects of CO2 storage. This provides new insights for the screening and selection of potential geological sites for CO2 storage.

Calculating the large leakage flux of a breached hydrocarbon trap using geophysical interpretation of a paleo-gas-water contact

Integration of three-dimensional seismic and well data from the Northern Carnarvon Basin on the North West Shelf of Australia was used to assess the evidence for top seal breach of a paleo-gas accumulation. Several seismic indicators of vertical hydrocarbon leakage from the crest of the stratigraphic Mungaroo Trap point to a significant flux of gas within the past few hundred thousand years. Mapping of the top reservoir within the Triassic aged Mungaroo Formation revealed strong evidence for a paleo-gas-water contact (GWC), approximately 100 m down flank from the erosional crest of the trap. This contact conforms to structure and delimits an original volume of 1.1 trillion cubic feet (Tcf), based on reservoir property calibration from nearby wells. Mapping also revealed a present-day gas-water contact with a closed volume of 0.2 Tcf, 30 m down flank from the crest. This contact displays a discordant geometry indicative of a dynamic contact.The leakage zone is located directly above the crest of the structure. It is seismically well imaged and comprises seafloor pockmarks, shallow gas anomalies and gas hydrate anomalies. The presence of a leakage zone distributed vertically above a reservoir containing a present and paleo-GWC provides compelling evidence this trap has leaked by breaching of the top seal. Volumetric calculations using the two GWCs indicate that the Mungaroo Trap has been depleted by 0.9–1.1 Tcf. A dynamic-GWC indicates the leakage event within the trap has occurred recently. Analysis of dating of horizons correlated to the seafloor pockmarks places the leakage event at sometime within the last 300 Ka.

What Next After a Decade With Significant Advances in the Application of Ultradeep Azimuthal Resistivity Measurements?

Equinor has played an important role in the last decade in the testing and development of ultradeep azimuthal resistivity (UDAR) measurements both for look-ahead and look-around applications. Today, UDAR technology is applied in more than 70% of Equinor’s high-angle or horizontal wells. In this paper, the authors will review the use of UDAR in Equinor over the last decade and highlight both successful use and real-time challenges related to the interpretation of the inversion results. UDAR technology and inversion algorithms have been very powerful for reservoir mapping to geosteer or geostop according to plan. However, we forget far too often the fact that we need a good understanding of the reservoir to interpret and evaluate the uncertainty in the inversion result. The number one mistake in a real-time setting is to interpret a resistivity contrast as a specific layer in the reservoir (for instance, top reservoir) and hold on to that same interpretation, even if we drill away from that contrast and may cross multiple layers as distance to the observed contrast increases. Other challenging real-time UDAR exercises relate to uncertainties in the prediction of resistivity inside the reservoir and reservoir thickness from inversion results when still drilling above the reservoir. A third mistake often seen in real time is the detailed interpretation of one-dimensional (1D) inversion results, even when other indicators are pointing towards two-dimensional (2D)/three-dimensional (3D) complexities in the reservoir. Equinor and other operators have pushed for more and more advanced inversion solutions, leading to 3D mapping capabilities for more complex reservoirs. The UDAR advances over the last few years are important for Equinor’s planned roadmap ahead. However, 1D through 3D inversion results can result in bad decisions if the uncertainty in the inversion result is not managed correctly. We see a need to investigate how to best exploit UDAR technology and inversion results without extending assumptions beyond an acceptable uncertainty level. Better handling of uncertainties in geosteering operations will become increasingly important for the well economy with smaller targets, complex geological settings, and varying sweep efficiencies. How can we best handle the uncertainty in inversion results in real-time operations to avoid inaccurate decisions that can potentially destroy well economy? This is an important question that will be addressed and should be handled in the future if UDAR technology is to continue its important role in well placement in the next decades.

Mechanisms of remaining oil formation by water flooding and enhanced oil recovery by reversing water injection in fractured-vuggy reservoirs

To get a deeper understanding on the formation mechanisms and distribution laws of remaining oil during water flooding, and enhanced oil recovery (EOR) mechanisms by reversing water injection after water flooding, 3D visualization models of fractured-vuggy reservoir were constructed based on the elements and configuration of fractures and vugs, and typical fracture-vug structures by using advanced CT scanning and 3D printing technologies. Then, water flooding and reversing water injection experiments were conducted. The formation mechanisms of remaining oil during water flooding include inadequate injection-production well control, gravity difference between oil and water, interference between different flow channels, isolation by low connectivity channel, weak hydrodynamic force at the far end. Under the above effects, 7 kinds of remaining oil may come about, imperfect well-control oil, blind side oil, attic oil at the reservoir top, by-pass residual oil under gravity, by-pass residual oil in secondary channel, isolated oil in low connectivity channel, and remaining oil at far and weakly connected end. Some remaining oil can be recovered by reversing water injection after water flooding, but its EOR is related to the remaining oil type, fracture-cavity structure and reversing injection-production structure. Five of the above seven kinds of remaining oil can be produced by six EOR mechanisms of reversing water injection: gravity displacement, opening new flow channel, rising the outflow point, hydrodynamic force enhancement, vertically equilibrium displacement, and synergistic effect of hydrodynamic force and gravity.

Recognition and application of single sand-body in fluvial facies

In the ultra-high water cut stage, the remaining oil of Lasaxing oilfields in Daqing placanticline, shows the distribution characteristics of highly dispersed and locally enriched, and the remaining geological reserves are still mainly distributed in fluvial reservoirs. In order to search and excavate the remaining oil of thick reservoir, the fine description technology of fluvial reservoir under the condition of dense well pattern was studied, and the recognition technology of meandering river and braided river single sand body was formed, which deepened the understanding degree of channel sand reservoir heterogeneity. The main controlling factors of remaining oil are defined, and the distribution mode of remaining oil is established, which can effectively guide the design of horizontal wells at the top of thick reservoir and the adjustment and exploitation of in-layer remaining oil tapping.