Top Of Reservoir Research Articles

Geological feature clarification of the contact zone of Akhskaya and Cherkashinskaya formations on the example of Priobskaya area

The first phase of subcycle AC12 formation on the example of the southern part of the Priobskoye field is considered. The job is done based on 3d seismic and geological model complexing with the using log interpretation. The erosion zone that violates the original structure of the upper part of the deep-sea clay pack III of akhskaya formation by paleochannels was revealed. These erosions form lithologic traps, isolated from the top productive reservoirs of subcycle AC12.

Analysis of bottom hole pressure of unsteady flow in dual-medium fracturing vertical well

In order to improve the validity of bottom hole pressure model, and simplify its calculation process, a mathematical model of instantaneous pressure for unsteady flow was established by considering the crossflow between the fractures and matrix. Different conditions, including the reservoir top has constant pressure, were considered. The basis for obtaining bottom hole pressure is to solve diffusivity equation with the integration of axisymmetric transformation and similar methods, which is presented for the first time. Different from the traditional method of using the Green’s function and source solution, this paper uses Laplace transformation, axisymmetric transformation and similar methods, separation of variables to obtain the analytical solution of Laplace domain. Then, the Stephenson Numerical method was used to obtain the numerical solution in a real domain. The results of this method agree with the numerical simulations and actual test data, suggesting the validity and accuracy of this method. Finally, the sensitivity analysis revealed that the pressure curve can be divided into eight stages, namely, early linear flow, continuous flow transition section, fracture linear flow, formation linear flow, crossflow, transitional flow, pseudo-radial flow and boundary control flow. The advantage of the analytical solution utilized in this paper is to incorporate exchange coefficient and skin factor efficiently, providing a theoretical basis for optimizing production pressure difference and determining the reasonable productivity.

Influence of reservoir-scale heterogeneities on the growth, evolution and migration of a CO2 plume at the Sleipner Field, Norwegian North Sea

New analysis of the baseline (pre-injection) seismic data at Sleipner has revealed large-scale, roughly north-trending, channelled ‘fairways’ at a range of stratigraphical levels in the Utsira Sand. The baseline data also reveal localised stratigraphical ‘point discontinuities’ within the reservoir, some of which show evidence of having provided vertical conduits for earlier natural gas flow. The repeat time-lapse seismic datasets, where finer details of reservoir geology are illuminated by the reflective CO2, show smaller-scale, north-trending and sometimes sinuous channels within the larger channel fairways. They also show a number of vertical CO2 pathways within the CO2 plume, corresponding to the point discontinuities seen on the baseline data.Reservoir flow models were set up with flow properties constrained only by the observed levels of CO2 accumulation in the reservoir and the arrival time of CO2 at the reservoir top just prior to the first repeat seismic survey in 1999. The initial model with laterally homogeneous sand units separated by thin semi-permeable mudstones achieved only a moderate match to the observed time-lapse seismic data. Subsequent flow models, progressively incorporating higher permeability vertical CO2 pathways through the mudstones and large-scale channel fairways within the reservoir sands, yielded a progressive and marked improvement in the history-match of key CO2 layers within the plume. Crucially, no layer-specific model calibration was employed to achieve this improvement.New geophysical measurements from Utsira Sand core have recently become available. These measurements provide important constraints on rock physics models of CO2 and brine mixtures in the Utsira Sand. An empirical Brie fluid mixing law for intermediate fluid saturations provides a good fit to the new laboratory data, allowing measurements of CO2 saturation to be converted into seismic velocity. This rock physics model was used to convert CO2 saturation distributions predicted by the most realistic reservoir model into a seismic velocity model of the CO2 plume. Synthetic seismic reflectivity profiles generated using this velocity model show a striking resemblance to the observed time-lapse seismic data, both in terms of plume layer reflectivity and also of time-shifts within and beneath the CO2 plume. This provides confidence in the fidelity of the preferred reservoir model solution.These results represent a significant breakthrough in the understanding and modelling of CO2 plume development at Sleipner. We emphasise that the improvements were brought about not by fine tuning reservoir properties to fit the observed time-lapse data, but simply by incorporating geological permeability features that can reasonably be inferred from the baseline seismic data.

Structural Modeling of the Top Turonian Reservoir in the Northern Seme Oilfield (Benin, West-Africa)

The Sèmè oilfield is located in Benin’s offshore coastal sedimentary basin, near the Benin-Nigeria border, and contains two important oil bearing structures called “Sèmè North” and “Sèmè South”. In this coastal basin, Turonian sandstones of Abeokuta formation (Cenomanian-Turonian to Early Senonian age) form two reservoir units differentiated by two seismic horizons H6 and H6.5. The H6 seismic horizon represents the upper reservoir unit and is the main reservoir from which, more than 22 million barrels of crude oil had previously been produced in Sèmè oilfield. In order to improve knowledge of field petroleum geology, the present study presents the structural features of this upper reservoir unit. The use of Petrel software modules for the integration of 15 wells data, allowed presenting a structural model and illustrative cross sections that precise the geometry and specifying the structural characteristics of this reservoir unit within Sèmè field. The displayed structural architecture shows that the upper Turonian sandstones unit is composed of 11 layers including 7 reservoir layers (A, B, C1, C2, D1, D2, E) and 4 intra-reservoir layers (1, 2, 3 and 4) controlled by faults systems. The model provides basic framework necessary for geological characterization of the reservoir through a static model. The results of this study can be used for petrophysical modeling, Gross Rock Volume (GRV) determination and technical redevelopment of the field.

Landing with confidence and accuracy in a big bore subsea gas producer – an integrated approach for setting a critical casing point in the Jansz-Io field development

As part of the Gorgon Stage 2 project, a total of four production wells were installed at a new manifold within the Jansz-Io gas field. A key well construction challenge was the placement of the 12 ¼″ section total depth (TD). Due to the presence of reservoir depletion, the mud weight required to drill the sandstone would be insufficient to prevent wellbore collapse in the Barrow Shale immediately above the reservoir. Hence, the casing design called to isolate the entire Barrow Shale interval by placing the 9 ⅝″ production liner shoe immediately inside the reservoir. To avoid damaging the high-quality sandstone in the upper reservoir, it was desired to limit the reservoir penetration to less than 1m true vertical depth (TVD) at 80° inclination. Chevron recognised several challenges in landing the wells, which included: seismic uncertainty of the reservoir top, poor resistivity contrast and the lack of significant markers in the overburden. Conventional methods such as near-bit gamma ray carried high risk because the sensor offset to bit is close to the penetration limit. Therefore, a new approach of integrating a deep directional resistivity (DDR) tool and an at-bit resistivity measurement to make the casing point decision was proposed. With this new approach, all four wells were landed, with actual reservoir penetration less than 1m TVD. The real-time data from the DDR tool allowed the operator to efficiently drill the section, only reducing the rate of penetration immediately prior to entering the reservoir. The at-bit resistivity tool, drilling parameter changes and cuttings identification were beneficial to confirm reservoir entry and call section TD.

High Resistivity Reservoirs (Causes And Effects): Sahara Field, Murzuq Basin, Libya

High and low resistivity values is an alarming phenomenon that is usually associated with a very complicated reservoir history and worth looking into. Ordovician sandstone reservoirs are the primary oil producers in the Murzuq basin oil fields that is characterized with an average porosity of 14%, permeability range 410-10,760 md and clean quartz aranite composition. More than fifty wells were drilled in Sahara oil field, but only four of them were announced to have high resistivity values more than 100k ohm-m and ten others to be considered as low resistivity wells (below 50 ohm-m). Therefore, average deep resistivity was mapped in both water and oil legs using all available data set, and the top reservoir was employed as a trend map. They showed distinctive trends for low resistivity readings in oil-leg and confirmed the extreme deep resistivity nature for the wells (W7, W8, W9, and W10). Height above oil water contact and capillary pressure was also calculated for all the wells and revealed a high pressure (400 psi) at the location of the high resistivity wells. As a result, of higher capillary pressure in thicker reservoir area oil might have been able to displace water through geological time by benefitting of more considerable height above oil-water contact, higher connate pressure, and buoyancy forces support, which resulted in occupying all the larger pores and pushed the water into minor scattered pores leading to gradual alteration of reservoir wettability from water to oil-wet. Hence, the brine fluids will no longer be connected to each other inside the pore system. Therefore, they will lose their contribution to resistivity readings, and the resistivity tool will encounter a more resistant medium, which in turn will lead to underestimation of water saturation.

Geothermal potential of the Tubbergen Formation in the Twente region of east Netherlands

We have determined the potential geothermal prospectivity of clean sandstones in the Tubbergen Formation (Late Carboniferous) of the Twente area (eastern Netherlands). We were motivated by the prevailing paradigm that in the Netherlands geothermal power can only be harvested economically through large, expensive installations producing high volumes from high-quality aquifers located between approximately 1500 and 2500 m. No such aquifers are present in Twente. We found that heat production is economically feasible from the Tubbergen Formation sandstones by producing smaller volumes from smaller, highly efficient installations that can be developed at considerably lower cost. Our reinterpretation of publicly available seismic and well data shows that potentially suitable sandstones occur over the whole area with thicknesses of up to 50 m, porosities reaching 20%, and permeabilities reaching 300 mD. The Tubbergen Formation is approximately 400–700 m thick in the study area and contains approximately 60% sandstone. The top reservoir reaches an approximate 1500 m depth in the southwest, and the base reaches some 4300 m in the northeast of the study area. The temperature is expected to range between 60°C and 140°C depending on the depth. The Carboniferous is densely faulted with a block size of approximately 3 × 4 km, each block being a potential target for geothermal development. To determine the economic feasibility, we performed an economic screening for a hypothetical location north of the city of Enschede and backed this up by reservoir simulations. The geologic risks of the Tubbergen Formation are the lack of permeability, reservoir thickness, and lateral extent of the reservoirs. In our judgment, the chance of economic success for this site is 50% or more. Upside potential is present in numerous fault blocks in the study area and in adjacent areas where suitable sandstones with similar porosity and permeability at greater depth and higher temperatures are expected.

НАУКОВЕ ОБҐРУНТУВАННЯ РЕГУЛЮВАННЯ ПРОЦЕСІВ ЕВТРОФІКАЦІЇ ВОДНИХ ОБ’ЄКТІВ (НА ПРИКЛАДІ РІЧКИ ВОРСКЛИ)

У статті проведено дослідження процесу евтрофікації водних екосистем. Визначено, що нині усвіті активно здійснюється розробка теоретичних основ і пошук практичних заходів з боротьби змасовим розвитком ціанобактерій у поверхневих водоймах. Водночас питання використання бакте-рій для очищення поверхневих водних об’єктів є на сьогодні недостатьо вивченими, постає потребав дослідженні евтрофікаційних процесів водних об’єктів при використанні різних методів біологіч-ного очищення. Зважаючи на це, метою роботи стало дослідження хімічних та біологічних методіввідновлення водних об’єктів через зменшення в них кількості ціанобактерій, на основі чого наданінаукові рекомендації щодо боротьби із «цвітінням» поверхневих водоймищ. Методика дослідженнявключала проведення аналітичних, натурних та лабораторних досліджень, розрахункову частину.Для дослідження процесу евтрофікації води в річці Ворскла було взято проби на глибині 0,2‒0,5 м відповерхні водойми (в різних районах м. Полтави та на околицях міста). На першому етапі дослі-дження вивчали хімічні методи боротьби із «цвітінням води». Найкращий результат спостерігалипри застосуванні перманганату калію (0,2*106 кл/л), молібденової рідини (0,3*106), магнезіальної су-міші (0,4*106), хлору (0,5*106) та хелату заліза (0,6*106). На другому етапі дослідження проводилививчення пробіотиків для боротьби із «цвітінням води» на наявність токсичної дії до ціанобактерій.З’ясовано, що використання біологічних методів очищення водних об’єктів від ціанобактерій є більшефективним порівняно з хімічними методами, зокрема використання пробіотику Світеко-Агробіотик-01, який ефективно знищує ціанобактерії до 94 %. Такий результат отримано при за-стосуванні перманганату калію (0,2*106), але негативним наслідком цього є те, що використанняхімічних методів загалом створює вторинне забруднення водоймищ. Також визначено ефективністьінших хімічних методів боротьби із «цвітінням води»: молібденової рідини (ефективність – 91 %),магнезіальної суміші (88 %), хлору (85 %) та хелату заліза (82 %). Дещо гірші результати дало за-стосування нітрату срібла (70 %) та хлориду барію (41 %). Найбільша кількість синьо-зелених водо-ростей залишилася при дії на останні сульфату алюмінію спільно з мідним купоросом (26 %). Прове-дені дослідження є основою розробки комплексних систем очистки водних екосистем екологічно без-печними методами від ціанобактерій, що є одним із пріоритетів розвитку урбанізованих територійта сталого розвитку суспільства.

Prediction of abnormal pressure from AVO velocities over “Safety” field, onshore Niger delta, Nigeria

Abnormal pressure prediction was undertaken in ‘‘Safety’’ field, onshore Niger Delta, Nigeria using amplitude variation with offset (AVO) velocities information. Each of the methods used form an integral part of a process that produces AVO Analysis, AVO velocity inversion, extraction of seismic velocity from AVO velocities inversion results and pore pressure prediction. Pore pressure predicted from the seismic velocity has a better resolution than the pressure predicted from the interval transit time. The pore pressure within the field ranges from 14.7psi to 3916psi. Overpressured and underpressured zones were delineated on the field from the pressure predicted from the seismic velocities. Within the field, the over-pressured zones were delineated at depth 6855 ft–7802 ft. Over pressure top was delineated at a depth of 6855 ft with a pore pressure of 3053psi and a corresponding hydrostatic pressure of 2722psi. The under-pressured zones were also delineated at depth 7883 ft–9288 ft. The under pressure top was delineated at a depth of 7883 ft with a pressure of 1093psi and a corresponding hydrostatic pressure of 3122psi. Porosity values within the over pressure zone ranges from 23% to 53% which could be considered as relatively high. This could be as a result of the fact that the pore fluid cannot be expelled rapidly thereby causing the pore fluid to increase rapidly since they are no longer compacted; thus leading to overpressure. As a result of overpressure top which is directly above the reservoir top within the shale zone, drilling this reservoir vertically could not be suggested so as to avoid possible blow out. It was also observed that the primary cause or mechanism of overpressure within this field could be disequilibrium compaction.

Johan Sverdrup’s Digital Operations Drive Efficiency, Safety

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30477, “Johan Sverdrup: The Digital Flagship,” by Paal Frode Larsen, Tor Tønnessen, and Florian Schuchert, Equinor, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The sheer size of the Johan Sverdrup field development (expected recoverable reserves of 2.7 billion bbl, with projected operations of more than 50 years) has earned it designation as the operator’s digital flagship. The field has driven digital solutions and work flows that have the potential to be scaled up for the benefit of the operator’s entire portfolio. The complete paper describes the development of the “digital field worker” at Johan Sverdrup, an initiative that has changed the approach toward not only construction and completion but also operations. Introduction The field is approximately 150 km west of Stavanger in the North Sea in a water depth of 110-120 m (Fig. 1). The top reservoir is approximately 1800 m below mean sea level. The reservoir is characterized by hydrostatic pressure and undersaturated oil with a low gas/oil ratio. A predrilling campaign included eight oil producers and 12 injectors. Additional wells will be drilled to achieve the expected Phase 1 oil production capacity of 70,000 m3/d. The field has been developed in two phases. Phase 1 was approved by Norwegian authorities in 2015 and includes four bridge-linked platforms, all with jacket substructures. Primary power to the field is supplied from shore. The full field development includes 64 wells, both platform and subsea wells. The field came onstream in October 2019. Ramp-up of the predrilled wells proceeded smoothly to a field-production level of approximately 350,000 B/D. Phase 2 of the development was approved in 2019 and is expected to start production in Q4 2022. At peak, this field will account for approximately one-third of all oil production in Norway with record low emissions. The expected full-field (Phase 1 and 2) production capacity is 105,000 m3/d at peak. Breakeven price for the full-field development is less than $20/bbl.

Exploration into the potential for a low-enthalpy geothermal power plant in Cape fold belt

South Africa has long been dependent on coal and other fossil fuels for cheap electricity generation. While there has been an increase in utilising renewable energy over the last two decades, the main focus has been on solar and wind, which are intermittent, with geothermal energy not even considered. With advances in technology that harness geothermal energy, geothermal resources as low as 85 °C have been reported attainable when using low-enthalpy technologies as such binary systems. This makes geothermal energy a reality for regions in South Africa where moderately high geothermal gradients exist.The initial high level assessment of the geothermal potential of the Cape Fold Belt region was done through accessing eight hot springs found to have the highest temperature from previous studies. Temperature measurements were taken as close to the source as possible as well as collection of water samples for ICP-AES analysis for major cations. The cation concentrations from the ICP-AES analysis (completed with the Thermo ICap 6200 ICP-AES) allowed for geothermometry calculations to be conducted which gave the minimum temperature estimates of the reservoirs of each hot spring. Both the surface temperature measurements and the estimates of the reservoir temperature resulted in two locations that were in the top three for both measurements. These two locations were Calitzdorp and Caledon, having water temperatures of 47 °C and 45 °C at surface and estimates of the reservoir temperatures of 117 °C ± 13 °C and 108 °C ± 21 °C respectively.The hydro-geological analysis of the Oudtshoorn region, where the Calitzdorp hot spring is located, was conducted using published geophysical data in the form of magneto-telluric (MT) survey that was carried out in 2005 by the Agulhas-Karoo Geoscience Transect project. The MT data was presented in a paper by Weckmann et al. (2012) as a cross sectional profile from Mossel Bay to Prince Albert to a depth of 30 km, where a large region of low resistivity was found below the Oudtshoorn basin. The Calitzdorp hot spring is positioned at the surface above this region. The geological cross sections and regional interpretation presented in this study infers that a major syncline of the Cape Supergroup exists below the basin, potentially as deep as 10 km, and covers the low resistivity area shown in the MT profile. This led to the inference that the large region of low resistivity is most probably due to a large water reservoir. This potential reservoir is about 40 km in length with a depth of 2.5 km–7 km at its thickest, tapering out towards the edges.The depth to the top of the potential reservoir and the estimated reservoir temperature from the geothermometry results in a geothermal gradient of 39 °C/km ±4.3 °C/km. Thus Calitzdorp was identified as a promising location for further exploration, ideally deep boreholes or more geophysical surveys, to validate the existence of a reservoir and take down-hole temperature measurements. The depth and size of this potential reservoir would make it a favourable candidate for a pilot low-enthalpy geothermal power plant within the Cape Fold Belt and South Africa.

A geothermal field study in Kızıldere (Aydın) region

Kizildere geothermal field is located in the Aegean graben systems. The study area comprises Kizilkaya, Igdecik, Sazak, Kolonkaya, and Tosunlar formations consisting of marbles, limestones, conglomerates, sandstones, travertines, and alluviums. The wells were drilled to develop the Kizildere geothermal field, and the reservoir temperatures in the wells were various between 170 and 212 °C. There are three reservoir rocks in the Kizildere geothermal area. The top reservoir rock is limestone with limited lateral continuity in the Pliocene-aged Sazak formation. The limestones have low porosity, low permeability, and low temperature at about 180 °C compared to other reservoir rocks. The middle reservoir rock, which has a slightly higher porosity and permeability, is represented by Igdecik formation consisting of the alternation of marble-quartz-schist. It has known that there is a hydrostatic pressure relation between these two aquifers. The quartzites are the deepest reservoir in the Kizildere region. According to the data in R-1 well, quartzites have high permeability and high temperature, which is about 242 °C. The water analysis in the Schoeller diagram demonstrated that the origins of water were the same; however, the amount of ion in water was different. According to the Piper diagram, water samples were classified as a water class with carbonate alkalinity. Finally, the Giggenbach diagram analysis confirmed that the water class of almost all of the water samples were determined as partially in equilibrium condition.

Reservoir simulation of Ulumbu geothermal field using TOUGH2 and ITOUGH2 simulator

Ulumbu geothermal field is classified as a natural two-phase geothermal system, located in the south of Mandosawu - Ranakah Old volcanics and Pocoleok, Flores Island. This field produces 4 x 2.5 MW electric power in 2014 until now with temperature between 230–240 °C. This study aims to perform reservoir simulation in the Ulumbu field. The reservoir simulation method aims to determine the reservoir characteristics of the geothermal field. This research used TOUGH2 and ITOUGH2 simulator to simulate the reservoir. The work concept from TOUGH2 is forward modeling while ITOUGH2 is inverse modeling. Both of methods will produce an output. The output of this research is natural state model that was validated by three wells of the actual measurement (pressure and temperature) and heat flow from the conceptual model. A pressure and temperature profiles are very representative with the data in the three wells. The reservoir location is between Poco Leok and Poco Rii (upflow zone) and continues to the southwest (outflow zone) with an average area of 10.5 km2. The top reservoir is at an elevation of 500 m, while the depth is up to -2000 m. Reservoir rock has a permeability value of around 10−14–10−15 m2, porosity value of 8–10 %, density value of 2500 kg/m3, and specific heat capacity value of 900 J/kgK. Temperature distribution results of the natural state model show the hydrogeological profile of the Ulumbu geothermal system. The natural state model is then used to help undertake a geothermal field development scenario, that is, to calculate resource reserves and to make recommendations for subsequent drilling zones.

Healing Behavior of Simulated Fault Gouges From the Groningen Gas Field and Implications for Induced Fault Reactivation.

We investigated the frictional strength recovery (healing) and subsequent reactivation and slip‐weakening behavior of simulated fault gouges derived from key stratigraphic units in the seismogenic Groningen gas field (N. E. Netherlands). Direct‐shear, slide‐hold‐slide (SHS) experiments were performed at in situ conditions of 100 °C, 40 MPa effective normal stress and 10–15 MPa pore fluid pressure (synthetic formation brine). Sheared gouges were allowed to heal for periods up to 100 days before subsequent reshearing. The initial coefficient of (steady) sliding friction μ was highest in the Basal Zechstein caprock (μ = 0.65 ± 0.02) and Slochteren sandstone reservoir (μ = 0.61 ± 0.02) gouges, and the lowest in the Ten Boer claystone at the reservoir top (μ = 0.38 ± 0.01) and in the Carboniferous shale substrate (μ ≈ 0.45). Healing and subsequent reactivation led to a marked increase (∆μ) in (static) friction coefficient of up to ~0.16 in Basal Zechstein and ~0.07 in Slochteren sandstone gouges for the longest hold periods investigated, followed by a sharp strength drop (up to ~25%) and slip‐weakening trajectory. By contrast, the Ten Boer and Carboniferous gouges showed virtually no healing or strength drop. Healing rates in the Basal Zechstein and Slochteren sandstone gouges were significantly affected by the stiffness of different machines used, in line with the Ruina slip law, and with a microphysical model for gouge healing. Our results point to marked stratigraphic variation in healed frictional strength and healing rate of faults in the Groningen system, and high seismogenic potential of healed faults cutting the reservoir and Basal Zechstein caprock units, upon reactivation.

A Discrete Fracture Modeling Approach for Analysis of Coalbed Methane and Water Flow in a Fractured Coal Reservoir

As a complex two-phase flow in naturally fractured coal formations, the prediction and analysis of CBM production remain challenging. This study presents a discrete fracture approach to modeling coalbed methane (CBM) and water flow in fractured coal reservoirs, particularly the influence of fracture orientation, fracture density, gravity, and fracture skeleton on fluid transport. The discrete fracture model is first verified by two water-flooding cases with multi- and single-fracture configurations. The verified model is then used to simulate CBM production from a discrete fractured reservoir using four different fracture patterns. The results indicate that fluid behavior is significantly affected by orientation, density, and fracture connectivity. Finally, several cases are performed to investigate the influence of gravity and fracture skeleton. The simulation results show that gas migrates upwards to the top reservoir during fluid extraction owing to buoyancy and the connected fracture skeleton plays a dominant role in fluid transport and methane production efficiency. Overall, the developed discrete fracture model provides a powerful tool to study two-phase flow in fractured coal reservoirs.

Feasibility study of gas injection in low permeability reservoirs of Changqing oilfield

Changqing is the largest petroleum-producing field in China and one-third of its production is attributed to the formations with permeability lower than 1 mD. Based on the recent successes of gas injection pilots in North America, we investigated the feasibility of gas injection in the low permeability Chang 63 reservoir of Changqing. An eight-component fluid characterization, which fitted the measured PVT data, was used in a dual-porosity compositional model. A typical well pattern was selected for the simulation study. The key input parameters were adjusted to match the historical data. Huff-n-Puff using different gases shows that the richer the injected gas, the higher the oil production. C3H8 huff-n-puff achieves the best performance, increasing the cumulative oil production by a factor of 2.28 after 5 cycles, then followed by C2H6 and the produced gas. CH4 demonstrates a lower recovery factor (RF) than waterflood, because its minimum miscibility pressure is close to the maximum allowable injection pressure, i.e., the minimum horizontal stress. With the current well placement design where the producer is at the reservoir top, the miscible bank, which forms at the front of lean gas injection, will be displaced towards the reservoir bottom even out of the stimulated reservoir volume (SRV), undermining its performance. Rich gas is more compatible, as the miscible bank forms at the injection tail. Based on the fracture spacingsfrom the published work, we could, for the first time, verify the technical feasibility of rich gas injection in Chang 63 following the presented compositional modeling framework.

Reunderstanding and significance of high-quality reservoirs of the inner Dengying Formation in the Anyue Gas Field

The overall development of the top of the gas reservoir of the Dengying Formation, Upper Sinian in the Anyue Gas Field of the Sichuan Basin, has been deployed, and the inner Dengying Formation is the next potential succession layer. However, the high-quality reservoirs of inner Dengying Formation are undeveloped and cannot be identified on the seismic profiles, which restricts its deepened understanding, exploration and development. In this paper, the logging and seismic response characteristics of high-quality reservoirs were analyzed using the mud logging and well logging data of the Anyue Gas Field, and a seismic response model for high-quality reservoir was established by means of seismic forward modeling. Then, the target processing was carried out for the problem of weak effective signals. Finally, the plane distribution of high-quality reservoirs of inner Dengying Formation and the favorable exploration areas were predicted. And the following research results were obtained. First, there are two types of high-quality reservoirs inside the Dengying Formation, i.e., concentrated vug type and independent cave type. Vertically, the independent cave reservoirs are mainly distributed within 100 m above the mudstone floor of the third Member of Dengying Formation. Horizontally, karst zones are developed along the bed. Laterally, they are scattered and beaded. And the scale is small. Second, seismic response of high-quality reservoirs inside the carbonate rocks is characterized by single-peak concealed “beaded” reflection, whose peak energy is relatively weak and can be easily covered by the noise of seismic data. Third, deep-seated weak signal recovery and processing technology can be used to deal with the weak seismic response of high-quality cave reservoirs, improve the amplitude preservation and S/N ratio of seismic data, and obtain the beaded reflections on seismic profiles so as to realize effective identification of high-quality cave reservoirs. In conclusion, the deep-seated weak signal recovery and processing technology is proved to be operable because the achieved results conform to the drilling data and the seismic forward modeling conclusions. In addition, high-quality cave reservoirs are developed at the bottom of the fourth Member of Dengying Formation, and they are locally distributed in a large scale. Therefore, it's one of the favorable succession layers for the following natural gas exploration and development of the Anyue Gas Field.

Integration of fluid replacement modeling and seismic AVO analysis towards simultaneous seismic inversion to delineate the distribution of Globigerina limestone gas reservoir

Integration of fluid replacement modelling and seismic AVO analysis towards simultaneous seismic inversion had been done to delineate the distribution of Globigerina limestone gas reservoir in Madura Strait, East Java Basin. This study was using backward modelling or well known as inversion modelling to finish the quantitative analysis. The purpose of the study is to map the distribution of Globigerina limestone gas reservoir so that in the end the final result will be used as a guidance to drill the next exploration well. It started with an optimized low frequency model building by integrating fluid substitution modelling and seismic AVO analysis. By integrating these two methods, the distorted top and bottom reservoir can be compensated, and the low frequency model will be optimized. The availability of the data includes 3D seismic data with acquisition bin size 18.75 m × 12.5 m, with two well logs. The cross plot result showed that the reservoir and non-reservoir lithology can be distinguished by Vp and Vs log. By analysing the acoustic impedance together with Vp/Vs ratio, the character of gas reservoir at surrounding F and H structures can also be delineated. The main cut off for acoustic impedance and Vp/Vs ratio were 5,500 gr/cm3*m/s and 2.0. The final optimizing result of low frequency model showed that the target G structure, which will be the next exploration target, showed an analogue response with its neighbour F and H structures. It is concluded that by integrating both two methods, fluid replacement modelling and AVO seismic analysis, the optimizing of low frequency model can be achieved and the simultaneous seismic inversion can successfully map other gas reservoir.

Analysis of major controlling geological factors on coalbed methane enrichment and accumulation model of low coal rank in Tuha-Santanghu Basin

The low-rank coalbed methane resources in the Tuha-Santanghu Basin are rich, but the degree of exploration is low. The main controlling factors and accumulation model of coalbed methane accumulation are insufficiently understood, which restricts the exploration and development practice. In order to find out the main controlling factors and accumulation mode of low rank coalbed methane in Tuha-Santanghu Basin, from the aspects of low coal rank coal seam distribution, coalbed methane gas types and origins, comprehensive considerations such as hydrogeology, tectonic and sedimentary conditions, etc, the reservoir-forming conditions of low rank coalbed methane gas are analyzed, and the accumulation model is proposed to further explore direction. The results show that hydrogeological condition affect the generation and enrichment of low rank coalbed methane in this area, which is an important conditions for the formation of low rank coalbed methane. It is advantageous to save the low-rank coalbed methane with weak runoff. Different tectonic conditions have different effects on the preservation of coalbed methane, which can be divided into favorable preservation and destructive preservation. The influence of coal-forming environment on coal’s gas-generating potential, top and bottom lithology and coal reservoir physical has an important impact on low rank coalbed methane. The comprehensive study proposes two types of low-rank coalbed methane accumulation models in the Tuha-Santanghu Basin: gas accumulation model of basin margin slope zone and gas accumulation model of stagnant confined water + lithologic plugging coalbed methane in small fault sag. Comprehensive analysis shows that coal-bearing slope zone of basin margin with favorable hydrogeological conditions and coalbed methane reservoir with good preservation conditions in small fault sag with retaining confined water+lithologic plugging characteristics will be the key exploration area in the future.

Applications of real-time chemical stratigraphy in support of the safe drilling of HPHT wells: examples from the Shearwater Field, Central North Sea, UK

X-ray fluorescence (XRF) data from a series of high-pressure–high-temperature (HPHT) wells drilled in the Shearwater Field, UK Continental Shelf (UKCS) are presented. These data comprise a total of 789 samples across a series of eight study wells. Chemical stratigraphy was utilized in conjunction with other geological data (i.e. well logs, ditch cutting descriptions and biostratigraphic analyses) to aid real-time stratigraphic placement. Systematic changes in geochemical composition were identified and used to build a chemostratigraphic zonation to aid delineation of lithostratigraphic boundaries. The application of chemical stratigraphy provided a valuable source of data, particularly through critical ‘drill-in-liner’ sections that are devoid of conventional logging while drilling (LWD) data. The identification of key geochemical zones and provision of a synthetic gamma-ray (Synth GR) profile were utilized in the placement of key casing points and identification of challenging top reservoir picks (Fulmar Formation). These data also served as a backup during LWD tool failure resulting from excessive temperatures. The successive addition of geochemical data accumulated with each well-site exercise permitted continued refinement of the zonation framework, with derived Synth GR profiles exhibiting an extremely close relationship with subsequent wireline logs. Chemical stratigraphic data are shown to be robust and repeatable within the Shearwater Field, enabling close stratigraphic control through critical sections, whilst also providing a low-cost backup in the event of conventional logging tool failures.