Journal articles on the topic 'Bottom water-drive oil and gas condensate reservoirs'

Horizontal Wells are often used to develop condensate gas reservoirs. When there is edge water in the gas reservoir, it will have a negative impact on the production of natural gas. Therefore, reasonable prediction of its water breakthrough time is of great significance for the efficient development of condensate gas reservoirs.At present, the prediction model of water breakthrough time in horizontal Wells of condensate gas reservoir is not perfect, and there are mainly problems such as incomplete consideration of retrograde condensate pollution and inaccurate determination of horizontal well seepage model. Based on the ellipsoidal horizontal well seepage model, considering the advance of edge water to the bottom of the well and condensate oil to formation, the advance of edge water is divided into two processes. The time when the first water molecule reaches the bottom of the well when the edge water tongue enters is deduced, that is, the time of edge water breakthrough in condensate gas reservoir.The calculation results show that the relative error of water breakthrough time considering retrograde condensate pollution is less than that without consideration, with a higher accuracy. The example error is less than 2%, which can be effectively applied to the development of edge water gas reservoir.

At present, multiphase flow productivity calculation requires many parameters, and most of them only consider oil and gas two-phase flow, which is complicated and limited. Therefore, a reasonable productivity formula of condensate gas reservoir with producing water is needed. The three-zone model of condensate gas reservoirs is generally applied to the physical model for inferring productivity. On this basis, an improved model is established, which includes that different seepage characteristics are considered for different zones. Moreover, the effects of inclined angle and water production on gas wells are regarded as pseudo-skin factors and additional-skin factors. In addition, Zone I considers the effects of high-speed nonDarcy effect(HSND), starting pressure gradient, stress sensitivity, inclined angle and water production; Zone II is the same way excepting starting pressure gradient and stress sensitivity ; Zone III only considers the effects of inclined angle and water production. As a result, a productivity equation with multiple factors for condensate gas wells is established. Through analysing cases and influences in H gas reservoir X1 well, the HSND, starting pressure gradient, stress sensitivity and water production have a negative impact on gas well productivity, but the inclined angle is opposite. Founded that the starting pressure gradient impacts on productivity is less than the HSND because of the limited radius of Zone I; the impact of the HSND on productivity increases with the decreasing of bottom hole pressure; the impact of water production on gas well productivity is much higher. When the angle is over 60°, the effect of gas

The Yamburg oil and gas condensate field, like many northwestern fields, is at the final stage of production. The consequence is that the large amount of formation water in the inflow may accumulate in particular in well bottom hole. The response surface analysis is used as a new technique for gaining detailed understanding of the relationships between combinations of two predictor variables and a result variable. This approach was applied to the Yamburg field in order to estimate the time of gas-water contact lift considering the lithological characteristics of the reservoirs. The results of the predicted gas-water contact time were compared to the expected gas-water contact time, the data of which were considered for the study. Using the parameters of the model as well as the three-dimensional response surface, which was built to facilitate and improve the interpretation of the results, it was possible to predict the gas-water contact time under certain conditions.

AbstractThe Skarfjell oil and gas discovery, situated 50 km north of the Troll Field in the NE North Sea, was discovered by well 35/9-7 and was appraised by three additional wells operated by Wintershall, in the period 2012–14.The Skarfjell discovery is an example of a combined structural/stratigraphic trap. The trap formed along the northern edge of a deep WNW–ESE-trending submarine canyon, which was created by Volgian erosion of intra-Heather, Oxfordian-aged sandstones and then infilled with Draupne Formation shales. This mud-filled canyon forms the top and side seal, with the bottom seal provided by Heather shales. The reservoir comprises mid-Oxfordian deep-water turbidites and sediment gravity flows, which formed in response to tectonic hinterland uplift and erosion of the basin margin, 10–20 km to the east.The Skarfjell discovery contains light oil and gas, and may be subdivided into Skarfjell West, in which the main oil reservoir and gas cap have known contacts, and Skarfjell Southeast, which comprises thinner oil and gas reservoirs with slightly lower pressure and unknown hydrocarbon contacts.The Upper Jurassic Draupne and Heather formations are excellent source rocks in the study area. They have generated large volumes of oil and gas reservoired in fields, and discoveries for which the dominant source rock and its maturity have been established by oil to source rock correlation and geochemical biomarker analysis. The Skarfjell fluids were expelled from mid-mature oil source rocks of mixed Heather and Draupne Formation origin.The recoverable resources are estimated at between 9 and 16 million standard cubic metres (Sm3) of recoverable oil and condensate, and 4–6 billion Sm3 of recoverable gas. The Skarfjell discovery is currently in the pre-development phase and is expected to come on stream in 2021.

Like many of the fields in northwest Siberia, the Yamburg oil and gas condensate field is in the final production stages. This, therefore, results in an accumulation of a large amount of formation water in the inflow at the bottom of the well. Response surface analysis is used as a new technique to gain a detailed understanding of the relationships between combinations of two predictor variables and an outcome variable. This approach was applied to the Yamburg field to estimate the time of the gas-water contact, considered as the result variable, by taking into account two groups of predictive variables which correspond to the reservoirs grouped by their lithological characteristics. The results of the predicted gas-water contact time were compared to the expected gas-water contact time, the data of which were taken into account for the study. Using the model parameters as well as the three-dimensional response surface, which was constructed to facilitate and improve the interpretation of the results, it was then possible to predict the gas-water contact time under certain conditions.

Summary Petroleum fluids from shale light-oil and gas/condensate reservoirs generally have a high content of normal paraffins. Paraffin-wax deposition is among the challenges in shale gas and oil production and in offshore flow assurance. Low-dosage chemical additives can be effective in paraffin-wax mitigation because of their high efficiency and economics. These additives are divided into broad categories of crystal modifiers and dispersants with vastly different molecular structures and mechanisms in wax-crystal-particle stabilization and wetting. This investigation focuses on the understanding of the differences in the aggregate size and morphology of chemical additives, and it centers on (1) wax-particle sedimentation from diluted petroleum fluids in vial tests, (2) wax-crystal-particle-size distributions and morphology by dynamic light scattering (DLS) and polarized-light microscopy, and (3) the wetting state from the effect of water. In two of the three petroleum-fluid samples used in this work, there is no visible precipitation at the bottom of the vials at temperatures below the wax-appearance temperature (WAT). The microscopic image of fluids along the length of the tube shows that the wax-particle size and intensity increase from top to bottom. To observe precipitation, we dilute the crude with a hydrocarbon such as n-heptane. The sedimentation of wax is then observed. The petroleum fluids used in this work have very low asphaltene content, and there is no complication from asphaltene precipitation. Our study shows that a small amount of crystal modifier and dispersant can reduce crystal-particle size to the submicron scale, and change the crystal morphology. We investigate the differences in the mechanisms of dispersants and crystal modifiers in bulk. Water, which is often coproduced with petroleum fluids, can increase the effectiveness of dispersants significantly by altering the wetting state of the wax-particle surface. Such enhancement is not found in crystal modifiers. Both additives affect the rheology of petroleum fluids.

This paper presents the numerical density derivative approach (another phase of numerical welltesting) in which each fluid’s densities around the wellbore are measured and used to generate pressure equivalent for each phase using simplified pressure-density correlation, as well as new statistical derivative methods to determine each fluid phase’s permeabilities, and the average effective permeability for the system with a new empirical model. Also density related radial flow equations for each fluid phase are derived and semilog specialised plot of density versus Horner time is used to estimate k relative to each phase. Results from 2 examples of oil and gas condensate reservoirs show that the derivatives of the fluid phase pressure-densities equivalent display the same wellbore and reservoir fingerprint as the conventional bottom-hole pressure BPR method. It also indicates that the average effective kave ranges between 43 and 57 mD for scenarios (a) to (d) in Example 1.0 and 404 mD for scenarios (a) to (b) in Example 2.0 using the new fluid phase empirical model for K estimation. This is within the k value used in the simulation model and likewise that estimated from the conventional BPR method. Results also discovered that in all six scenarios investigated, the heavier fluid such as water and the weighted average pressure-density equivalent of all fluid gives exact effective k as the conventional BPR method. This approach provides an estimate of the possible fluid phase permeabilities and the % of each phase contribution to flow at a given point. Hence, at several dp' stabilisation points, the relative k can be generated.

Summary We present formulation and numerical solution of two-phase multicomponent diffusion and natural convection in porous media. Thermal diffusion, pressure diffusion, and molecular diffusion are included in the diffusion expression from thermodynamics of irreversible processes. The formulation and the numerical solution are used to perform initialization in a 2D cross section. We use both homogeneous and layered media without and with anisotropy in our calculations. Numerical examples for a binary mixture of C1/C3 and a multicomponent reservoir fluid are presented. Results show a strong effect of natural convection in species distribution. Results also show that there are at least two main rotating cells at steady state: one in the gas cap, and one in the oil column. Introduction Proper initialization is an important aspect of reliable reservoir simulations. The use of the Gibbs segregation condition generally cannot provide reliable initialization in hydrocarbon reservoirs. This is caused, in part, by the effect of thermal diffusion (caused by the geothermal temperature gradient), which cannot be neglected in some cases; thermal diffusion might be the main phenomenon affecting compositional variation in hydrocarbon reservoirs, especially for near-critical gas/condensate reservoirs (Ghorayeb et al. 2003). Generally, temperature increases with increasing burial depth because heat flows from the Earth's interior toward the surface. The temperature profile, or geothermal gradient, is related to the thermal conductivity of a body of rock and the heat flux. Thermal conductivity is not necessarily uniform because it depends on the mineralogical composition of the rock, the porosity, and the presence of water or gas. Therefore, differences in thermal conductivity between adjacent lithologies can result in a horizontal temperature gradient. Horizontal temperature gradients in some offshore fields can be observed because of a constant water temperature (approximately 4°C) in different depths in the seabed floor. The horizontal temperature gradient causes natural convection that might have a significant effect on species distribution (Firoozabadi 1999). The combined effects of diffusion (pressure, thermal, and molecular) and natural convection on compositional variation in multicomponent mixtures in porous media have been investigated for single-phase systems (Riley and Firoozabadi 1998; Ghorayeb and Firoozabadi 2000a).The results from these references show the importance of natural convection, which, in some cases, overrides diffusion and results in a uniform composition. Natural convection also can result in increased horizontal compositional variation, an effect similar to that in a thermogravitational column (Ghorayeb and Firoozabadi 2001; Nasrabadi et al. 2006). The combined effect of convection and diffusion on species separation has been the subject of many experimental studies. Separation in a thermogravitational column with both effects has been measured widely (Schott 1973; Costeseque 1982; El Mataaoui 1986). The thermogravitational column consists of two isothermal vertical plates with different temperatures separated by a narrow space. The space can be either without a porous medium or filled with a porous medium. The thermal diffusion, in a binary mixture, causes one component to segregate to the hot plate and the other to the cold plate. Because of the density gradient caused by temperature and concentration gradients, convection flow occurs and creates a concentration difference between the top and bottom of the column. Analytical and numerical models have been presented to analyze the experimental results (Lorenz and Emery 1959; Jamet et al. 1992; Nasrabadi et al. 2006). The experimental and theoretical studies show that the composition difference between the top and bottom of the column increases with permeability until an optimum permeability is reached. Then, the composition difference declines as permeability increases. The process in a thermogravitational column shows the significance of the convection from a horizontal temperature gradient.

A12 oil and gas reservoirs in L Oilfield Carboniferous carbonate rocks of oil and gas bearing system, saturated with the gas cap and edge water and bottom water reservoir. The A12 oil and gas reservoir structure the relief of the dome-shaped anticline, oil, gas and water distribution controlled by structure, the gas interface -2785 meters above sea level, the oil-water interface altitude range -2940 ~-2980m, average-2960m. Average reservoir thickness of 23m, with a certain amount of dissolved gas drive and gas cap gas drive energy, but not very active edge and bottom water, gas cap drive index.

Water inflow to petroleum wells hampers production of oil or gas leading to early shut downs of the wells without sufficient recovery of hydrocarbons in place. Downhole water sink (DWS) is a completion/production technique for producing water-free hydrocarbons with minimum amount of water from reservoirs with bottom water drive and strong tendency to water coning. DWS eliminates water invasion to hydrocarbon production by employing hydrodynamic mechanism of coning control in situ at the oil-water or gas-water contact. The mechanism is based upon a localized water drainage generated by another well completion (downhole water sink) installed in the aquifer beneath the oil/water or gas/water contact. The paper summarizes the development and state-of-the-art of DWS technology. Presented are results from theoretical studies, physical and numerical experiments, and field projects to date. It is demonstrated that DWS could increase recovery and control water production in vertical and horizontal oil wells—with natural flow, downhole pumps or gas lift, and in the gas wells producing from low-pressure tight gas reservoirs. To date, DWS has been used in reservoirs with bottom water. Moreover, in principle, the technology might also be used in the dipping reservoir structures with encroaching side-water.

AbstractIn this work, the petrophysical properties of Abu Madi reservoir in El-Qara Field at northern Nile Delta Basin (NDB) were evaluated depending on well logging data of two wells: El-Qara-2 and El-Qara-3. This evaluation revealed that in El-Qara-2 well, the promising gas zone is detected between depths of 3315 and 3358 m, while in El-Qara-3 well, the best gas interval is detected between depths of 3358 and 3371 m. In addition to the production test parameters (gas rate, condensate rate, gas gravity, condensate gravity, gas-to-oil ratio, flowing tubing head pressure, flowing bottom hole pressure, and static bottom hole pressure), the calculated petrophysical parameters (shale volume, total porosity, effective porosity, and water saturation) for both intervals were relatively similar. This confirms that the investigated wells were drilled at the same reservoir interval within Abu Madi Fm. The depth variation in the examined zones was attributed to the presence of buried normal faults between El-Qara-2 and El-Qara-3 wells. This observation may be supported from the tectonic influence during the deposition of Abu Madi Fm. as a portion of the Messinian syn-rift megasequence beneath the NDB.

The problem of monitoring and preventing deposit inundation is becoming increasingly important in Ukraine. The solution to this problem is one of the ways to ensure the energy independence of the state. The operation of producing wells is complicated by the accumulation of liquid at the bottom. Subsequently, it leads to premature shutdown of the wells. Inundation determines the need to isolate the influx of formation water. Considering the significant residual reserves of gas trapped in water, it is important to improve existing technologies and to develop new ones for the development of depleted fields under the conditions of dynamic water drive in order to ensure maximum hydrocarbon recovery rates. This paper summarizes domestic and foreign field development technologies under water pressure conditions and analyzes the main disadvantages and advantages of the existing methods of stimulating hydrocarbon inflows in waterlogged gas and gas condensate wells. The main factors that determine the causes and nature of flooding of productive formations and ways to prevent them are analyzed. Based on the results of the analysis of laboratory and experimental studies, the behavior of gas trapped by brine water has been established.But the issue of determining the localization of residual reserves has not been studied sufficiently. Considering the above mentioned ideas, the author asserts the necessity to and to use geological and technological models constantly. It ensures better extraction of the residual gas from depleted fields under the condition of intensive advance of reservoir water into productive formations. In the case of adapting the three-dimensional model to the actual data of the production history and the simulation of the exact breakthrough of produced water in production wells, there comes the possible to determine the most promising zones and sections of the field, the reservoirs of which are characterized by the best filtration-capacitive properties and significant gas reserves. The use of a constantly operating geological and technological model of the field will make it possible to develop ways of extracting the residual gas reserves trapped in produced water, to improve existing production technologies and to ensure maximum recovery factors.

Using the main tools of hydrodynamic modeling, the study of the influence of production well operating parameters on the regulation effectiveness of the gas condensate reservoirs’ flooding process by injection of carbon dioxide at the initial gas-water contact has been carried out. The study has been undertaken for various values ​​of gas flow rate. The simulation results indicate a high technological efficiency of using carbon dioxide as an injection agent. High displacing properties of carbon dioxide provide an increase in the mobility of formation fluids (condensate, oil) and a decrease in the mobility of formation water. The introduction of the technology for injecting carbon dioxide into productive reservoirs at the initial gas-water contact provides the creation of additional hydrodynamic and filtration resistance on the path of formation water movement. Due to which the inflow of formation water into gas-saturated horizons is partially blocked and waterless operation of production wells is ensured during a longer period of further field development. Based on the results of processing the calculated data, the optimal value of the rate of natural gas production has been determined under the carbon dioxide injection into the productive reservoir at the boundary of the gas-water contact, outside of which the gas recovery factor changes insignificantly. At the time of the carbon dioxide breakthrough into the production wells, the optimal production rate of the production well is 55.93 th.m3/day. The predicted gas recovery factor for the given optimal value of the gas production rate is 64.99 %, and when developing for depletion it is 58.34 %. The results of the studies carried out indicate the technological efficiency of the introduction of technologies for injecting carbon dioxide into reservoirs, which are developed in a water drive in order to regulate the process of formation water flow into productive reservoirs and increase the final gas recovery factor.

The CO2-Assisted Gravity Drainage process (GAGD) has been introduced to become one of the mostinfluential process to enhance oil recovery (EOR) methods in both secondary and tertiary recovery through immiscibleand miscible mode. Its advantages came from the ability of this process to provide gravity-stable oil displacement forenhancing oil recovery. Vertical injectors for CO2 gas have been placed at the crest of the pay zone to form a gas capwhich drain the oil towards the horizontal producing oil wells located above the oil-water-contact. The advantage ofhorizontal well is to provide big drainage area and small pressure drawdown due to the long penetration. Manysimulation and physical models of CO2-AGD process have been implemented at reservoir and ambient conditions tostudy the effect of this method to improve oil recovery and to examine the most parameters that control the CO2-AGDprocess. The CO2-AGD process has been developed and tested to increase oil recovery in reservoirs with bottom waterdrive and strong water coning tendencies. In this study, a scaled prototype 3D simulation model with bottom waterdrive was used for CO2-assisted gravity drainage. The CO2-AGD process performance was studied. Also the effects ofbottom water drive on the performance of immiscible CO2 assisted gravity drainage (enhanced oil recovery and watercut) was investigated. Four different statements scenarios through CO2-AGD process were implemented. Resultsrevealed that: ultimate oil recovery factor increases considerably when implemented CO2-AGD process (from 13.5%to 84.3%). Recovery factor rises with increasing the activity of bottom water drive (from 77.5% to 84.3%). Also,GAGD process provides better reservoir pressure maintenance to keep water cut near 0% limit until gas flood frontreaches the production well if the aquifer is active, and stays near 0% limit at all prediction period for limited waterdrive.

The article presented information about specific of geological conditions depleted oil and gas fields, which has Remaining Oil and Gas in Place. The reasons of abnormally low pressure nascency in the deposit has been analyzed. The article presents information about influence of geodynamic processes and structural and tectonics of Earth crust to formation pressure. The information about availability of initial abnormally low formation pressure in Ukrainian Oil and Gas-Condensate fields has been written. Supposition of nascence the abnormally low formation pressure in difficult oil/water/gas saturation geological formation has been analyzed. The drop of pressure in of initial formation has been analyzed and researched. The article presented that drop of pressure gradient in main Ukrainian oil and gas fields is equal to the value of abnormally low formation pressure.The problems of considerable remaining Oil and Gas in with abnormally low pressure in Ukrainian oil and gas field deposit has been analyzed. The information about oil and gas reservoir conditions of depleted field and brown fields in Ukraine has been analyzed.The plot of the formation pressure gradient decreasing for Chornukhynske, Denysivske, Solokhivske, Druzheliubivske, Tymofiivske and Yablunivske fields has been presented. The drop of pressure to abnormally low in Chornukhynske, Denysivske, Solokhivske, Druzheliubivske, Tymofiivske and Yablunivske fields has been established. The problems of drilling and cementing in the well with abnormally low pressure has been describe. Difficult geological conditions in Ukrainian oil and gas field deposit has been analyzed.The article shows the importance to control parameters of all technological liquids, especially density of drilling and cementing liquid in a time of drilling well with abnormally low pressure. The article shows the aspect of the using of lightweight grouting solutions for mounting wells with abnormally low reservoir pressures, the importance of controlling the contamination of the bottom zone of the formation and preventing the occurrence of hydraulic fracturing during cementing.

The paper considers modern methods for determining the position of gas-liquid contacts in terrigenous deposits at oil and gas condensate fields in Ukraine. The results of laboratory studies of a representative core collection (87 samples) in the petrophysical laboratory of IFNTUOG made it possible to establish the reservoir parameters and lithological characteristics of reservoir rocks of Carboniferous and Neogene sediments, which made it possible to reliably estimate the reservoir parameters of productive formations. The results of well studies, in particular, obtained during the isolation of oil and gas-saturated reservoir rocks and monitoring the dynamics of changes in oil-water and gas-water contacts, made it possible to form an optimal informative complex of geophysical methods for effective prospecting and development of oil and gas fields. Direct studies of the identified reservoir rocks made it possible to establish that the geological sections of the Jurassic, Cretaceous and Neogene systems of prospecting areas are filled with both hydrophilic and hydrophobic lithotypes of rocks, which have different effects on the readings of electrical and radioactive methods. Reasonably, the maximum value of the electrical resistivity, the maximum oil saturation coefficient (Кo), as well as the minimum value of the water saturation coefficient (Кw), which is typical for oil and gas-saturated formations, must correspond to the condition for displaying these parameters in completely water-saturated rocks. In this case, the boundary of the transition zone will be displayed by the bottom of the maximum radio-saturated layer and the top of the aquifer in this rock. Confirmation of the above is seen from the fragments of geophysical data processing, electrical and neutron studies in the presence of low and high salinity, drilling fluids and drilling fluids. The analysis of the efficiency of using the methods of pulsed neutron-neutron logging (PNNL) and neutron gamma-ray logging (NGL) when monitoring the change in the position of the GLC to prevent watering of productive formations is carried out. According to the research results, it is proposed to use a complex of nuclear physical methods in the process of monitoring the dynamics of changes in NWC, in particular, neutron gamma logging, repeated neutron logging, as well as in the process of drilling conducting electrical methods of imaginary resistance and unauthorized potentials.

The Pyrenees development comprises the concurrent development of three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin. The development will be one of the largest offshore oil developments in Australia for some time. It is a complex subsea development consisting of a series of manifolds, control umbilicals and flexible flowlines tied back to a disconnectable floating production, storage and offloading (FPSO) vessel. The development involves the construction of 17 subsea wells, including 13 horizontal producers, three vertical water disposal wells and one gas injection well. The project is presently on production with first oil achieved during February 2010. This paper gives an overview of the field development and describes the engineering and technologies that have been selected to enable the economic development of these fields. The Pyrenees fields are low relief, with oil columns of about 40 metres in excellent quality reservoirs of the Barrow Group. Two of the fields have small gas caps and a strong bottom water drive common to all fields is expected to assist recovery. The oil is a moderate viscosity, low gas-to-oil ratio (GOR), 19°API crude. Due to the geometry of the reservoirs, the expected drive mechanism and the nature of the crude, effective oil recovery requires maximum reservoir contact and hence the drilling of long near horizontal wells. Besides the challenging nature of well construction, other technologies adopted to improve recovery efficiency and operability includes subsea multiphase flow meters and sand control with inflow control devices.

AbstractThe Strathspey Field was the first sub-sea development in the North Sea to be tied back to a third party operator, the Ninian Field now operated by Canadian Natural Resources (CNR). The field was discovered in 1975 by well 3/4-4 and lies wholly within Block 3/4a. The field is a tilted fault block, unconformity trap and consists of two separate reservoirs, a volatile oil and a gas condensate reservoir: the Middle Jurassic, Brent Group and the Lower Jurassic/Upper Triassic, Banks Group respectively. Two 3D seismic surveys cover the field, the most recent being a Vertical Cable Seismic survey recorded in 1996.The Banks Group reservoir is produced under depletion drive by five wells and the Brent Group reservoir by water flooding with 3 water injectors and 6 producing wells. In place volumes are 290 BCF and 90MMSTB for the Banks Group and 120MMSTR in the Brent Group Reservoir. Ultimate recoveries are estimated to be 230BSCF, 22MMBBL and 70MMSTB, 88 BSCF respectively. Oil export is via the Ninian pipeline system to Sullom Voe, while gas export is through the Far North Liquids and Gas System (FLAGS) pipeline system to St Fergus.]

The problem of monitoring and preventing deposit inundation is becoming increasingly important in Ukraine. The solution to this problem is one of the ways to ensure the energy independence of the state. The operation of producing wells is complicated by the accumulation of liquid at the bottom. Subsequently, it leads to premature shutdown of the wells. Inundation determines the need to isolate the influx of formation water. Considering the significant residual reserves of gas trapped in water, it is important to improve existing technologies and to develop new ones for the development of depleted fields under the conditions of dynamic water drive in order to ensure maximum hydrocarbon recovery rates. This paper summarizes domestic and foreign field development technologies under water pressure conditions and analyzes the main disadvantages and advantages of the existing methods of stimulating hydrocarbon inflows in waterlogged gas and gas condensate wells. The main factors that determine the causes and nature of flooding of productive formations and ways to prevent them are analyzed. Based on the results of the analysis of laboratory and experimental studies, the behavior of gas trapped by brine water has been established.But the issue of determining the localization of residual reserves has not been studied sufficiently. Considering the above mentioned ideas, the author asserts the necessity to and to use geological and technological models constantly. It ensures better extraction of the residual gas from depleted fields under the condition of intensive advance of reservoir water into productive formations. In the case of adapting the three-dimensional model to the actual data of the production history and the simulation of the exact breakthrough of produced water in production wells, there comes the possible to determine the most promising zones and sections of the field, the reservoirs of which are characterized by the best filtration-capacitive properties and significant gas reserves. The use of a constantly operating geological and technological model of the field will make it possible to develop ways of extracting the residual gas reserves trapped in produced water, to improve existing production technologies and to ensure maximum recovery factors.

Summary For water-wet reservoirs, several expressions may be used to correlate capillary pressure, or height above the free water level, with the water saturation. These correlations all feature a vertical asymptote at the residual water saturation where the capillary pressure goes to plus infinity. We have developed a general capillary pressure correlation that covers primary drainage, imbibition, secondary drainage, and hysteresis scanning loops. The graph exhibits an asymptote at the residual saturation of water and of oil where the capillary pressure goes to plus and minus infinity, respectively. The shape of the correlation is simple yet flexible as a sum of two terms, each with two adjustable parameters and is verified by laboratory experiments and well-log data. An associated hysteresis scheme is also verified by experimental data. The correlation can be used to make representative capillary pressure curves for numerical simulation of reservoirs with varying wettability and to model and interpret flooding processes. Introduction Many capillary pressure correlations have been suggested in the literature,1–5 and they typically have two adjustable parameters. One parameter expresses the pore size distribution and hence the curvature of the pc curve, the other the actual level of the capillary pressure, i.e., the entry or the mean capillary pressure. Most of the correlations are limited to primary drainage and positive capillary pressures. Huang et al.5 extended their correlation to include all four branches of the bounding hysteresis loop: spontaneous and forced imbibition, and spontaneous and forced secondary drainage. They employed the same primary drainage expression to each branch, scaled to fit the measured pc axis crossing. We have chosen to base the general capillary pressure correlation for mixed-wet reservoir rock on the simple power-law form of Brooks and Corey 2,3 for primary drainage capillary pressure from Sw=1 to SwR. The classical expression for a water-wet core may be slightly rewritten to facilitate the extension of scope, p c d = c w d ( S w − S w R 1 − S w R ) a w d , ( 1 ) where cwd is the entry pressure, 1/awd the pore size distribution index,6 and SwR the residual (irreducible) water saturation. The main reason for choosing this basis is the experimental verification of Eq. 12,3 and its simplicity. According to Morrow,7 there is now wide acceptance of the view that most reservoirs are at wettability conditions other than completely water-wet. To our knowledge, however, no comprehensive, validated correlation has been published for mixed-wet reservoirs. The lack of correlation makes it difficult to properly model displacement processes where imbibition is of importance and data are scarce, e.g., bottom water drive and water-alternate-gas injection. In this article, we present a general capillary pressure correlation and an associated hysteresis loop scheme. We try to demonstrate the applicability of the correlation by fitting data from a series of membrane and centrifuge experiments on fresh cores, and we show that the correlation is well suited to represent measured capillary pressure curves over a wide range of rock types. Also, by analyzing well-log data from the same well in a bottom-water driven North Sea sandstone reservoir at several points in time, we are able to model the transition from the initial primary drainage saturation distribution to the later observed imbibition profile. The correlation crosses the zero capillary pressure axis at two points for the imbibition and the secondary drainage branches. These points, together with the residual saturations, define the Amott-Harvey wettability index.7 Thus, variations in wettability, e.g., with height, could be incorporated into the correlation. We adopt the terminology of Morrow7 to characterize the capillary pressure curve, Fig. 1: "drainage" denotes a fluid flow process where the water saturation is decreasing, even for an oil-wet porous medium; "imbibition" denotes a process where the oil saturation is decreasing; "spontaneous" imbibition occurs for positive capillary pressure, "forced" imbibition for negative capillary pressure; "spontaneous" (secondary) drainage occurs for negative capillary pressure, and "forced" (secondary) drainage for positive capillary pressure; "primary" drainage denotes the initial drainage process starting from Sw=1.0; and, for completeness, "primary" imbibition denotes a imbibition process starting from So=1. Correlation The design idea for the correlation is as follows: Eq. 1 is valid for a completely water-wet system and, if index w for water is substituted by index o it is equally valid for a completely oil-wet system. For other cases between these limits, a correlation should be symmetrical with respect to the two fluids since neither dominates the wettability. One way to achieve a symmetrical form that is correct in the extremes is to sum the two limiting expressions, i.e., to sum the water branch given by Eq. 1 and a similar oil branch, resulting in the general expression, p c = c w ( S w − S w R 1 − S w R ) a w + c o ( S o − S o R 1 − S o R ) a o . ( 2 ) The a's and c's are constants and there is one set for imbibition and another for drainage. An imbibition curve from SwR to SoR is modeled by Eq. 2 and the four constants (awi, aoi, cwi, coi), and a secondary drainage curve from SoR to SwR by the constants (awd, aod, cwd, cod). The constraints on the constants are that aw, ao, cw are positive numbers and co is a negative number. The plot of Eq. 2, both for imbibition and drainage, therefore consists of two branches, a positive water branch with an asymptote at Sw= SwR and a negative oil branch with an asymptote at Sw= SoR Fig. 1. Depicted in Fig. 1 are (1) the primary drainage curve starting at Sw =1 modeled by Eq. 2 with co=0 and cw equal to the entry pressure; (2) the primary imbibition curve from Eq. 2 with cw=0 and co equal to the entry pressure of water into a 100% oil saturated core; and (3) the bounding (secondary) imbibition and secondary drainage curves forming the largest possible hysteresis loop.

To date, Ukraine's mature gas fields, which are being developed in the gas regime, are at the final stage of development, which is characterized by a significant depletion of reservoir energy. The final stage of development requires solving complex problems related to watering wells, destruction of the reservoir, removal of formation water and mechanical impurities, increasing back pressure in the system, as well as the moral and physical wear and tear of industrial equipment. In the conditions of falling gas production, a significant part of the operating well stock is unstable, in the mode of unauthorized stops due to the accumulation of liquid at the bottom and insufficient gas velocities for removal to the surface, and also the accumulation of the liquid phase in the lowered places of the gas gathering system. Within the framework of the conducted studies, the gas dynamic models of the operation of the gas collection system of 3 oil/gas-condensate fields (OGCF) are created. A single model of the gas production system "reservoir - well - gas gathering system - inter-field gas pipeline - main facilities" is built. The current efficiency of the gas production, collection and transportation system is assessed. On the basis of model calculations, the current production capabilities of the wells are defined, as well as the "narrow" places of the system. It is established that the introduction of modern technologies for the operation of watered wells without optimizing the operation of the entire gas production system is irrational, since the liquid that is carried out from the wellbore will accumulate in the plumes and increase the back pressure level in the ground part. In conditions of increasing gas sampling, liquid flowlines can be taken out of the loops and deactivated the separation equipment. The feasibility of introducing methods for optimizing the operation modes of the gas production - gathering and transportation system is estimated, which allows choosing the optimal method for increasing the efficiency and reliability of its operation. For the first time in the Ukrainian gas industry, an integrated model of the field is created as a single chain of extraction, collection, preparation and transportation of natural gas, which can be adapted for the development and arrangement of both new and mature deposits. The main advantage of the application for the hydrocarbon production sector is the simulation of the processes, which makes it possible to evaluate the operating mode of the well in the safe zone while reducing the working pressure and introducing various intensification methods, and also to estimate the increase in hydrocarbon production. For the equipment of the ground infrastructure – "midstream" – the main advantage is a reduction in the time required to perform design calculations for gas pipelines, trains and pipelines for transporting multiphase media using public models. The creation and use of integrated models of gas fields gives an understanding of the integral picture of available resources and ensures an increase in the efficiency of field development management. The results of the calculation are clearly correlated with the actual data, which makes it possible to use the models constructed to obtain numerical results.

Enhanced Oil Recovery (EOR) applications are highly recommended and required in Yemen to maintain stable levels of oil production. The field selected for this research is located in Yemen, where relatively- thin sandstone reservoirs are dominant at moderate depths. The reservoir is highly undersaturated with an API gravity of 14.2 and a very low solution gas-oil ratio (GOR), initial oil viscosity (uo) of 420 cP. The reservoir is naturally producing with the support of a strong water drive at the bottom, however, the increase in water cut poses a disadvantage for this reservoir. Over time, the oil production will decline and development plans will be required to improve the oil recovery. This research aims to optimize oil recovery factor and the interest in the overall project economy by evaluating the optimization of the steam flood process based on the Stochastic analysis with the highest recovery factor (RF) and the highest net present value (NPV) objective functions. Two optimization techniques have been used to perform the data analysis, deterministic and stochastic approaches. The deterministic approach is carried out by direct analysis on the results of the technical optimization method using the CMG reservoir simulator, while the stochastic approach uses the simulation results from the deterministic approach to determine the most influencing parameter in the steam flood process as well as to optimize the infill and injection wells location, number of steam injection wells and the steam injection rate with the highest oil RF and highest NPV. In this field development using deterministic approach, two producer wells are converted into injector wells. The RF for this initial scenario is 52,34%, and the NPV is 33.10 MM$/STB. For the second scenario using Stochastic approach, CMOST optimization using the maximum RF objective function resulted in RF of 61.33%, and NPV of 43.00 MMS/STB. Finally for the third scenario using CMOST optimization with the maximum NPV objective function resulted in RF of 57.29%, and an NPV of 53.86 MMS/STB. The Stochastic approach with maximum NPV objective function provides the most favorable scenario to be used in the development of Field "AR". And the optimization using the stochastic approach also produces faster, optimum, and more accurate results than the deterministic approach since it forecast a variety of probable results by running thousands of reservoir simulations using many various estimations of economic conditions.

Summary Decline analysis inherently assumes a constant total-reservoir-fluid rate in contrast to constantly varying rates in actual field operations. This paper provides an approach for determining decline constants under varying total fluid rates for secondary or tertiary oil recovery processes. It further enables forecasting oil and nonoil production performance under different total fluid rate strategies. The technique helps identify pseudosteady state flow periods when decline analysis techniques are valid. It distinguishes incremental from accelerated oil responses when a recovery process change, operating practices, or workover activity causes a total fluid rate change. Introduction Decline analysis forms a very useful tool for extrapolating oil production into the future. The recovery of oil can be defined in terms of three basic parameters: the oil relative permeability, the drainage volume, and the pressure gradient. Problems arise in using decline analysis when changes to the relative permeability relationship or apparent drainage volume occur. The reservoir is said to be in transition during the period of changing drainage volume or relative permeability relationship (the latter induced by changes in recovery mechanism). Decline analysis is not appropriate during transition periods. However, decline analysis can incorporate corrections for changes in the pressure gradient. Pressure gradient changes result from many actions taken during production operations. These include reservoir pressure changes associated with pressure depletion under primary recovery, pressure increases resulting from secondary and tertiary fluid injection, and other voidage replacement practices. Pressure gradient changes also result from bottom hole producing pressures (or back pressure) associated with well flowing conditions, pump changes, pump efficiency losses, wellbore stimulations, and temporary shut ins. Pressure gradient changes are generally revealed as total fluid rate changes. A decline analysis procedure correcting for pressure gradient or total reservoir fluid rate (referred to here as the processing rate) changes during secondary and tertiary recovery addresses many common situations. Injection in excess of withdrawals can result in increasing reservoir pressure and in turn a period of increasing oil production making conventional decline analysis inappropriate. During postmortem workover and in-fill drilling analysis, such a method can provide the distinction between accelerated and incremental oil responses since acceleration manifests itself as an increase in the pressure gradient. A base production forecast is often used to calculate an incremental response from an operational change. Correcting the extrapolated base performance for changes in the actual total fluid rate is essential in determining the technical incremental oil response; an accurate technical incremental response enhances the quality of project management decisions such as under CO2 flooding. The example of Fig. 1 demonstrates some of the utility of the processing-rate-corrected-decline method of this paper. The decline constants were obtained by matching the performance over the history match period shown. The deviation of the actual performance from the conventional exponential semilog straight-line decline fit resulted from increasing the injection rate and in turn the processing rate. The processing rate correction matches this along with most of the other fluctuations in the actual oil rate. The split between the actual and processing rate corrected curves resulted from a change in the recovery mechanism from waterflood to CO2 Because the method handles processing rate changes, both an economic and technical incremental oil response can be ascertained. The literature offers several methods for handling processing rate or pressure gradient changes. Fetkovich1 provides a solution for changing back pressure using superposition in conjunction with decline type curves for undersaturated single phase flow and constant productivity index and drainage radius. Fetkovich et al.2 use superposition but extend it for solution gas drive. Blasingame, McCray, and Lee3 provide four different superposition approaches that yield an equivalent time for use with decline type curves. Fetkovich4 also proposes use of rate normalization during transient production when both the rate and bottom hole flowing pressure are declining smoothly. These approaches were formulated for conditions of constant wellbore pressure with depleting reservoir pressure (changing pressure gradient) assuming single phase flow (oil relative permeability remains constant). These solutions are not applicable to secondary or tertiary recovery processes characterized by changing pressure gradients and multiphase flow. The empirically derived Arps5,6 decline equations successfully apply to several physically induced oil rate decline conditions. Fetkovich1,2,4,7,8 derived the exponential and hyperbolic decline form of Arps' equations based on pressure depletion as the cause of declining oil production. Matthews and Lefkovits9 extended pressure depletion to gravity drainage. Oil also declines in an exponential or hyperbolic fashion due to declining oil relative permeability associated with depleting oil saturation as derived by Masoner.10 The technique presented in this paper addresses decline analysis under conditions of changing pressure gradients (processing rates) for reservoirs under multiphase flow where the oil relative permeability dominates the decline; these conditions occur under solution gas drive, secondary, and tertiary recovery methods. This paper develops the theoretical basis for the processing rate correction to decline analysis; describes how the approach can significantly improve the accuracy and flexibility of decline analysis; presents examples for both water and CO2flooding, in-fill drilling, and stimulations; and provides insights on use of the technique for increasing flood performance understanding. Theoretical Development This section develops relationships and equations for processing rate correcting decline analysis. It begins with the discussion of a series of assumptions in which the relative permeability link to oil decline forms the key. Two different mathematical approaches to solve the problem are then presented for the special case of waterflooding: constant-ultimate-reserves method, and fluid-cut-maturity method. The fluid-cut-maturity method is further generalized for any immiscible multiphase recovery mechanism.

Jersey Oil and Gas Unearths Wengen Prospect The Greater Buchan Area (GBA) now has four drill-ready prospects to add to discoveries already slated for development. In a new subsurface evaluation, Jersey Oil & Gas, a British-independent North Sea-focused upstream oil and gas company, has uncovered a new prospect, named Wengen, to complement its Verbier Deep, Cortina NE, and Zermatt drill-ready prospects. The four are estimated to host some 222 million bbl of P50 prospective resources, all in the immediate vicinity of Jersey’s planned GBA production facility. The consolidated Greater Buchan venture comprises Buchan field (80 million bbl), Verbier (c25 million bbl), J2 (c20 million), and Glenn (14 million). The new prospect, located in License P2170, is directly west of the Tweedsmuir field and should host some 62 million bbl of potential resources (P50), with the probabilistic range set at 31 million bbl at P90 (higher confidence) and 162 mil-lion for P10 (lower confidence). Probability of geological success is 22% for the prospect. Contractor Rockflow previously estimated the recoverable resources in the GBA at 94.7 million bbl, including the parts within P2170. In late November, Jersey announced it is taking full ownership of License P2170, which hosts most of the Verbier discovery, as part of the GBA. In March, Jersey told investors the project is fully funded and that it intends to take the project to potential industry partners via a farm-out process. An exploratory drilling campaign is being planned for 2022. Jordan Finds “Promising” Gas Reserves Near Iraq Border Jordan’s majority state-owned National Petroleum Company (NPC) has discovered “promising” natural gas in the Risha gas field along its eastern border with Iraq. Risha makes up nearly 5% of the kingdom’s consumption of natural gas of around 350 MMcf/D for power generation, Jordanian officials said. The flow of new gas supplies will raise the productivity of the gas field and help Jordan cut dependence on oil imports to fuel its power sector and industries. The country, which now imports over 93% of its total energy supplies, is burdened by a $3.5-billion annual bill, comprising almost 8% of Jordan’s GDP. Although British supermajor BP abandoned the eastern desert area in 2014 after investing over $240 million, Jordanian exploration has stepped up since 2019, boosting quantities by at least 70%, Mohammad al Khasawneh, head of NPC, said. An ambitious 10-year energy plan unveiled in 2019 aims to secure nearly half of the country’s electricity generation from local energy sources com-pared to a current 15%, according to Iraq Energy Minister Hala Zawati. The plan is meant to diversify local energy sources by expanding investments in renewable and oil shale to reduce costly foreign fuel imports, Zawati added. ExxonMobil Discovers Hydrocarbons Offshore Suriname ExxonMobil and Petronas have discovered several hydrocarbon-bearing sandstone zones with good reservoir qualities in the Campanian section of the Sloanea-1 exploration well on Block 52 offshore Suriname, adding to ExxonMobil’s finds in the Guyana-Suriname basin. The well was drilled by operator Petronas. ExxonMobil said in November that it is prioritizing near-term capital spending on advantaged assets with the highest potential future value. Maersk Drilling reported in early July that it had secured the Maersk Developer from Petronas subsidiary PSEPBV in a $20.4-million one-well exploration con-tract offshore Suriname. The semisubmersible rig drilled the Suriname-Guyana basin well to a total depth of 15,682 ft. “We are pleased with the positive results of the well,” Emeliana Rice-Oxley, Petronas’ vice president of upstream exploration, said. “It will provide the drive for Petronas to continue exploring in Suriname, which is one of our focus basins in the Americas.” Block 52 covers an area of 1.2 million acres and is located approximately 75 miles offshore north of Paramaribo. The water depths on Block 52 range from 160 to 3,600 ft. ExxonMobil E&P Suriname BV, an affiliate of ExxonMobil, holds 50% interest in Block 52. PSEPBV is operator and holds 50% interest. CNOOC Starts Production on Penglai 25-6 Oil Field Area 3 Project China National Offshore Oil Corporation (CNOOC) announced on 14 December that its Bohai Sea Project - the Penglai 25-6 oil field area 3 - has started production ahead of schedule. The biggest offshore oil field and the second biggest oil field in China, the Penglai is located in the south central Bohai Sea, with average water depth of about 27 m. In addition to fully utilizing the existing processing facilities of Penglai oil fields, the project has built a new wellhead platform and plans 58 development wells, including 38 production wells and 20 water-injection wells. The project is expected to reach its peak production of approximately 11,511 B/D of crude oil in 2023. Six successful appraisal wells were also drilled, which confirmed the presence of hydrocarbons in reservoirs located with-in Miocene, Lower Minghuazhen, and Guantao sandstones. The Penglai 19-3 oil field is located in Block 11/05 of Bohai Bay, approximately 235 km southeast of Tanggu. The production-sharing contract for block 11/05 was signed between CNOOC and ConocoPhillips China (COPC) in December 1994; the field was discovered jointly by CNOOC and COPC in 1999. The oil field was developed in two phases. Phase I production started in December 2002; production from the wellhead platform C, which is tied back temporarily to the production facilities of Phase I, began in June 2007. Since June 2020, CNOOC has announced five production startups: the Jinzhou 25-1 oilfield 6/11 area project, the Liuhua 16-2 oilfield/ 20-2 oil-field joint development project, the Nan-bao 35-2 oilfield S1 area project, the Luda 21-2/16-3 regional development project, and the Qinhuangdao 33-1S oilfield phase-I project. In Q3 2020, CNOOC achieved a total net production of 131.2 million BOE, which the company said represented an increase of 5.1% year over year. Production from China was said to have increased by 10.4% year over year to 88.6 million BOE. In November, CNOOC revealed that the Liuhua 29-1 gas field had begun production; in September, the company said the Bozhong 19-6 condensate gas field pilot area development project had also begun. Operator CNOOC holds 51% interest while COPC holds 49% interest in the Penglai 25-6 oilfield area 3 project. Equinor’s Snorre Expansion Project Starts Ahead of Schedule, Below Cost Work began in December on the Snorre Expansion Project in the southern part of the Norwegian Sea. This increased-oil-recovery project will add almost 200 million bbl of recoverable oil reserves and help extend the productive life of the Snorre field through 2040. The expansion project is proposed in blocks 34/4 and 34/7 of the Tampen area, approximately 124 miles west of Florø in the Norwegian North Sea. “I am proud that we have managed to achieve safe startup of the Snorre Expansion Project ahead of schedule in such a challenging year as 2020. In addition, the project is set to be delivered more than NOK 1 billion below the cost estimate in the plan for development and operation,” Geir Tungesvik, Equinor’s executive vice president for technology, projects, and drilling, said. Originally scheduled to come onstream in the first quarter of 2021, the project comprises 24 new wells divided into six subsea templates, drilled to recover the new volumes. Bundles connecting the new wells to the platform have been installed, in addition to new risers. The project also includes a new module and modifications on Snorre A. In December 2017, Equinor submitted a modified plan for development and operation of the field. With the expansion, the recovery factor will increase from 46 to 51%, representing significant value for a field with 2 billion bbl of recoverable oil reserves. Wind power will supply about 35% of the power requirement for the Snorre and Gullfaks fields. The Hywind Tampen project, featuring 11 floating wind turbines, should start up in Q3 2022. The investments in the expansion project total NOK 19.5 billion (2020 value). The project has had substantial spin-off effects for the supply industry in Norway, particularly in eastern Norway and in Rogaland. The Snorre field partnership comprises Equinor (operator) 33.27%, Petoro 30%, Vår Energi 18.55%, Idemitsu 9.6%, and Wintershall Dea 8.57%. Petrobras To Sell Entire Stake in Onshore Field of Sergipe Petrobras on 11 December signed a contract with Energizzi Energias do Brasil to sell its entire stake in the onshore field of Rabo Branco, located south of the Carmópolis field in the Sergipe-Alagoas Basin, Sergipe state. The Rabo Branco field is part of the BT-SEAL-13 concession. The $1.5-million sale is in line with Petrobras’ strategy to cut costs and improve its capital allocation, to focus its resources increasingly on deep and ultradeep waters. The average oil production of the field, from January to October 2020, was 138 B/D. Energizzi Energias do Brasil will own 50% stake in the Rabo Branco field; operator Produção de Óleo e Gás (Petrom) holds the remaining 50%. On 10 December, Petrobras closed the divestiture of its full ownership in four onshore fields at the Tucano Basin site in the state of Bahia. Petrobras sold its entire interest to Eagle Exploração de Óleo e Gás (Eagle). Petrobras earned $2.571 million from this sale, in addition to the $602,000 that the company received at the time of signing the sale contract, for a total of $3.173 million. BP, Reliance Announce First Gas From Asia’s Deepest Project Oil-to-telecom conglomerate Reliance Industries Limited (RIL) and BP have started production from India’s first ultradeepwater gas project, the first of three such projects in the KG D6 block. The R Cluster gas field is located off the east coast of India, about 60 km from the existing KG D6 control-and-riser platform (CRP), and comprises a subsea production system tied back to the CRP via a subsea pipeline. It is the deepest offshore gas field in Asia at a depth greater than 2000 m. The companies’ next project, the Satellites Cluster, is expected to come on stream this year, followed by the MJ project in 2022. These projects will utilize the existing hub infrastructure in the KG D6 block. “Growing India’s own production of cleaner-burning gas to meet a significant portion of its energy demand, these three new KG D6 projects will support the country’s drive to shape and improve its future energy mix,” BP Chief Executive Bernard Looney said. The R Cluster field is expected to reach plateau gas production of about 12.9 million standard cubic meters per day (MMscm/D) in 2021. Peak gas production from the three fields should be 30 MMscm/D (1 Bcf/D) by 2023, about 25% of India’s domestic production, and will help reduce the country’s dependence on imported gas. RIL is the operator of KG D6 with a 66.67% interest; BP holds a 33.33% participating interest.

Abstract We have previously proposed the "inject low and let rise" strategy of storing CO2 in deep saline aquifers. The idea is to maximize the amount of CO2 stored in immobile forms by letting CO2 rise toward the top seal of the aquifer but not reach it. The distance that the CO2 rises depends on the uniformity of the displacement front. In this paper, we address the question of whether the intrinsic instability of a buoyancy-driven immiscible displacement leads to fingering. Fingers could reach the top seal of the aquifer, leading to an accumulation of CO2 at large saturations. We study the mechanisms governing this type of displacement in a series of fine-grid numerical simulations. Each simulation begins with a finite volume of CO2 placed at large saturation at the bottom of a 2D aquifer. Only buoyancy forces drive the displacement. Boundaries are closed, so CO2 rises and brine falls as the simulation proceeds. Several fine-scale geostatistical realizations of permeability are considered, and the effects of capillary pressure, anisotropy, and dip angle are examined. In these simulations, buoyant instability has very little effect on the uniformity of the displacement front. Instead, the CO2 rises along preferential flow paths that are the consequence of spatially heterogeneous rock properties (permeability, drainage capillary pressure curve, and anisotropy). Capillary pressure broadens the lateral extent of the flow paths. If the formation beds are not horizontal, capillary pressure and anisotropy can cause the CO2 to move predominantly along the bedding plane rather than vertically. Accurate assessment of CO2 migration after injection ends will therefore require accurate characterization of the spatial correlation of permeability in the target formation and of the capillary pressure and relative permeability curves. Introduction Storing CO2 in deep saline aquifers will be a key technology if society elects to limit the amount of greenhouse gases entering the atmosphere. Large-scale (106 tonnes of CO2 per year) examples of this type of storage are underway at Sleipner and In Salah, and more are planned (IPCC 2008). Effective mitigation of CO2 emissions will require many more projects of this type, storing on the order of 109 tonnes per year (Pacala and Socolow 2004). In terms of volumetric flow rates through wellbores, this rate of storage is of the same magnitude as the current global rate of oil production. Thus inexpensive, reliable methods of ensuring that stored CO2 remains in place will be essential. CO2 can be stored in an aquifer in four modes: as a bulk phase within a structural trap, as a residual phase trapped by capillary forces, as aqueous species dissolved in brine, and as a precipitated mineral. The latter three forms of storage are permanent in the sense that the CO2 will remain in the aquifer at least as long as the residence time of water in the aquifer. On the other hand, CO2 held in a structural trap at large saturations (above residual) is potentially mobile in that it will remain trapped only as long as the seal remains intact. Storage methods that reduce the amount of potentially mobile CO2 correspondingly reduce the risk of leakage over the long term. The inject-low-and-let-rise strategy is one such method (Kumar et al. 2005; Ozah et al. 2005). Under typical storage conditions, CO2 is less dense than brine. If CO2 is injected only into the lower part of an aquifer, then, after injection ends, the CO2 will continue to migrate, driven only by buoyancy. As CO2 rises into the upper part of the aquifer, it will leave behind a residual phase trapped by capillary forces. The permanency of residual phase trapping is the main motivation for this approach, but an additional benefit is that vertical movement toward the top seal is also retarded. By choosing the volume injected, one can, in principle, prevent the CO2 from reaching the top of the aquifer. The distance that the CO2 rises depends on the uniformity of the displacement front and on the saturation of CO2 behind the front. In this paper, we discuss factors that control the former feature. We will report on the latter in future publications. Coarse-grid simulations suggest that CO2 will rise in a compact plume having a smooth outline. As the grid is refined, the shape of plume becomes more uneven. Can this loss of uniformity be attributed to the intrinsically unstable character of buoyancy-driven immiscible flow? In analogy with immiscible displacements that exhibit viscous instability, we might anticipate the emergence of fingers as the CO2 rises. Such fingers conceivably could reach the top seal of the aquifer quickly, even when the volume of stored CO2 is insufficient to allow a uniform displacement to reach the top. This could lead to an accumulation of potentially mobile CO2, the very situation the inject-low-and-let-rise strategy seeks to avoid. Thus, it is important to assess the extent to which gravity fingers develop under typical storage conditions for a range of target formations. Some aspects of this problem are familiar from the long experience of gas and CO2 injection into oil reservoirs (Stalkup 1983). In gas-injection processes, the competition between viscous forces and buoyancy leads to gravity override. The larger mobility of the gas phase also leads to viscous fingering. We will see that some factors that govern gas-injection displacements also influence the situation of interest here--that is, when injection has ended and the only driving force is buoyancy. On one hand, this is not surprising. On the other, it should not be taken for granted because there has been relatively little examination of the buoyancy-dominated dynamics. The key question is whether the absence of competing forces allows the intrinsic instability of a buoyant displacement to dominate the shape of the plume. The idealized initial condition for our simulations is an approximation of the situation commonly observed at the end of the injection period in simulations of the inject-low-and-let-rise strategy. The simplification allows us to attribute differences in behaviors unequivocally to differences in petrophysical properties and to the physics of buoyant flow. The understanding thus obtained will provide insight into the post-injection behavior when the injection period is simulated more realistically.

The block deep condensate gas reservoir in the basin in the southeast of the South China Sea is a bottom water reservoir and is producing in the late effusion, which faces problems such as scaling, condensate oil–water two-phase flow, and low temperature at the subsea wellhead. The mud line for this kind of gas-well has characteristics including high condensate content in low temperature, high downhole temperature, and injection with a foam discharge agent and scale inhibitor. In this article, the influence of low temperature and scale inhibitor is considered for the first time, and a dynamic liquid-carrying experiment for the optimization and performance evaluation of foam discharge agents was carried out according to these characteristics. The experimental results show that the optimized foam discharge agent, ZHY-01, has good resistance to high temperature and condensate oil, and the optimal concentration of the foam discharge agent is recommended to be 0.25%. Under this concentration, the liquid-carrying capacity of the foam discharge agent decreases slightly by 10.17% at low temperature. The scale inhibitor MA/AA reduced the liquid-carrying capacity by 11.86%, and the scale inhibitor PESA reduced the liquid-carrying capacity by 10.17%. The research results in this article have certain reference significance for the chemical screening and evaluation of the foam drainage gas production process in deep-water condensate gas wells.

AbstractThe C oilfield is located in the Bohai Bay Basin, a typical strong bottom water reservoir. Oilfield reservoir and oil–water distribution are complex. At present, the C oilfield has entered the high water cut development stage, and it is challenging to stabilize oil and control water. The reservoir with an imperfect well pattern has dominant bottom water ridge channels, uneven oil–water interface uplift, limited water drive sweep range, and low inter-well reservoir production degree. The oil layer between the horizontal section of the production well and the top of the reservoir cannot be effectively developed, and the remaining oil is enriched. Therefore, it is urgent to explore new energy supplement methods to improve inter-well and vertical remaining oil production in the C oilfield. In this study, the displacement medium is optimized through indoor experimental simulation. From the experimental results, the remaining oil between the sand bodies can be used in heavy oil reservoirs, and the residual oil between wells can be significantly utilized in the alternate displacement of gas and foam, and the recovery degree of the reservoir is increased by 12.44%. The remaining oil at the top of the reservoir can be used in the upper reservoir to increase the remaining oil in the top of the reservoir by injecting gas and foam alternately in the new reservoir. The final recovery of the reservoir is increased by 6.00%. This experimental study guides tapping the potential of the remaining oil in the offshore strong bottom water reservoir.

The Gas Assisted Gravity Drainage (GAGD) process has become one of the most important processes to enhance oil recovery in both secondary and tertiary recovery stages and through immiscible and miscible modes. Its advantages came from the ability to provide gravity-stable oil displacement for improving oil recovery, when compared with conventional gas injection methods such as Continuous Gas Injection (CGI) and Water – Alternative Gas (WAG). Vertical injectors for CO2 gas were placed at the top of the reservoir to form a gas cap which drives the oil towards the horizontal oil producing wells which are located above the oil-water-contact. The GAGD process was developed and tested in vertical wells to increase oil recovery in reservoirs with bottom water drive and strong water coning tendencies. Many physical and simulation models of GAGD performance were studied at ambient and reservoir conditions to investigate the effects of this method to enhance the recovery of oil and to examine the most effective parameters that control the GAGD process. A prototype 2D simulation model based on the scaled physical model was built for CO2-assisted gravity drainage in different statement scenarios. The effects of gas injection rate, gas injection pressure and oil production rate on the performance of immiscible CO2-assisted gravity drainage-enhanced oil recovery were investigated. The results revealed that the ultimate oil recovery increases considerably with increasing oil production rates. Increasing gas injection rate improves the performance of the process while high pressure gas injection leads to less effective gravity mediated recovery.