Low Gas Oil Ratio Research Articles

Characterizing hydrocarbon discoveries and prospects in the Tay Sandstone using relative elastic inversion: Greater Pilot area, Central North Sea

The Pilot oil accumulation and associated discoveries of Blocks 21/27 and 21/28 have been stranded assets for three decades. The principal cause of delay in developing the oil fields is because these are heavy oils with low gas–oil ratio and, in some cases, significant gas caps. The oil in the Tay Sandstone is trapped in structural and stratigraphic closures at a depth of 800–1300 m. Determining pay thickness and delimiting oil-in-place in some existing discoveries and especially in undrilled prospects has been problematic. This difficulty has been addressed by conducting an innovative amplitude versus offset (AVO) inversion of the seismic data which has been successfully blind tested against the wells and prognosed closures. The method, which is a band-limited form of extended elastic impedance (EEI), has proved robust for discriminating gas-, oil- and brine-filled sands from one another. Oil and gas trapped further down-dip in the discoveries Fyne, Crinan and Dandy are developed in Tay reservoirs showing generally lower net-to-gross. The sensitivity of the rEEI attribute to the presence of thicker intervals of oil pay, in this case, is used to indicate where higher net-to-gross is present above the oil–water contact, a characteristic of direct relevance to the planning of optimally located development wells.

Revitalizing Reservoirs Nitrogen Kick-off Techniques for Reactivating Inactive Wells

This study explores the use of nitrogen (N2) injection to rejuvenate inactive wells and enhance reservoir productivity. We analyze the mechanism of N2 injection and its effectiveness in stimulating production from dormant wells through case studies and field applications. Our findings highlight the cost-effectiveness and environmental benefits of N2 kickoff in extending the life of mature reservoirs and maximizing hydrocarbon recovery. By examining operational conditions such as gas injection rate and pressure, we identify optimal conditions using Wellflo® simulations. Key factors like water cut, reservoir pressure, gas oil ratio, and productivity index (J) are considered to predict production outcomes. A new metric, the Optimum Economic Factor (OEF), assesses the efficiency of each operation based on production rate, operation length, and nitrogen usage. Our decision matrix, incorporating all examined factors, reveals trends: higher gas injection rates are needed for wells with higher water cut, lower gas oil ratio, lower productivity index, and lower reservoir pressure. We also studied the effects of wellhead pressure, well depth, and coiled tubing size, finding increased frictional pressure gradients with larger coiled tubing. Optimizing nitrogen unloading operations can significantly reduce costs, particularly by paying for coiled tubing packages on an hourly basis instead of daily rates. Our decision matrix facilitates planning and execution, optimizing nitrogen usage and reducing manpower requirements. Overall, our study demonstrates that proper optimization can make nitrogen unloading economically viable in mature oil fields.

Modeling of the movement of rich gas in a porous medium in immiscible, near miscible and miscible conditions

Gas injection is one of the most common enhanced oil recovery techniques in oil reservoirs. In this regard, pure gas, such as carbon dioxide (CO2), nitrogen (N2), and methane (CH4) was employed in EOR process. The performance of pure gases in EOR have been investigated numerically, but till now, numerical simulation of injection of rich gases has been scared. As rich gases are more economical and can result in acceptable oil recovery, numerical study of the performance of rich gases in EOR can be an interesting subject. Accordingly, in the present work the performance of rich gases in the gas injection process was investigated. Methane has been riched in liquefied petroleum gas (LPG), natural gas liquid (NGL), and Naphtha. Afterwards, the process of gas injection was simulated and the effect of injection fluids on the relative permeability, saturation profile of gas, and fractional flow of gas was studied. Our results showed that as naphtha is a heavier gas than the two other ones, IFT of oil-rich gas with naphtha is lower than other two systems. Based our results, gas oil ratio (GOR) and injection pressure did not affect the final performance of injection gas that has been riched in NGL and LPG. However, when GOR was 1.25 MSCF/STB, rich gas with naphtha moved with a higher speed in the domain and the relative permeability of each fluid and fractional flow of gas were affected. The same result was achieved at higher injection pressure. When injection pressure was 2000 psi, movement of gas with higher speed in the domain, alteration of relative permeability and changes in the fractional flow of gas were obvious. Therefore, based on our result, injection of naphtha with low pressure and high GOR was suggested for considered oil.

Performance of a tight reservoir horizontal well induced by gas huff–n–puff integrating fracture geometry, rock stress-sensitivity and molecular diffusion: A case study using CO2, N2 and produced gas

This work provides a comprehensive workflow with practical guidelines for integrating fracture-geometry, rock stress-sensitivity, and gas molecular diffusion to evaluate the performance of a tight reservoir horizontal well induced by gas Huff–n–Puff (HnP). The laboratory measurements and field results were integrated in numerical simulation. The stress-sensitivity led the permeabilities of the matrix and fractures to significantly decrease during primary depletion and HnP stages, thereby impairing well productivity. Rigorous characterizations of fracture-geometry and rock stress-sensitivity are crucial for history-matching and oil recovery simulation. During produced gas HnP, the cumulative oil production was reduced by 4.6% original oil in place (OOIP) because of the stress-dependent permeability. The hysteresis in fracture-permeability noticeably decreased the transport of mass and pressure but hardly affected the short-term production owing to the rapid closure of fractures during puff stage. The final oil recoveries induced by gas diffusion were 0.4%, 0.04% and 0.35% OOIP by CO2, N2 and produced gas HnP, respectively. The produced gas HnP process produced the highest efficiency of enhanced oil recovery than CO2 and N2 owing to its significant pressurizing effect and lower gas-oil ratio. Minimum-miscibility-pressure should not be the primary consideration for gas HnP in tight reservoirs.

Experimental Study on the Sweep Law of CO2 Miscible Flooding in Heterogeneous Reservoir in Jilin

It is very important to effectively describe the sweep characteristics of CO2 miscible flooding based on physical models for actual reservoir development. In this study, based on the geological characteristics of the Jilin ultra-low permeability reservoir, which has significant vertical heterogeneity, a two-dimensional double-layer heterogeneous visualization model with a permeability contrast of 10 and thickness contrast of 2 was designed to perform experimental research on the sweep law of CO2 miscible flooding with an injection-production mode of “united injection and single production”. With the goal of determining the obvious differences in the gas absorption capacity and displacement power of the two layers, the CO2 dynamic miscible flooding characteristics were comprehensively analyzed, and the sweep law of CO2 miscible flooding, including the oil and gas flow trend, migration direction of the oil–gas interface, and distribution characteristics of the miscible zone, was further studied in combination with the oil displacement effect. In this experiment, the gas absorption capacity was the key factor affecting the sweep efficiency of the CO2 miscible flooding. Under the combined influence of the internal and external control factors of the reservoir thickness, permeability, and injection-production mode, the gas absorption capacity of the high-permeability layer was much greater than that of the low-permeability layer, resulting in the retention of a large amount of remaining oil in the low-permeability layer, which effectively displaced and swept the oil in the high-permeability layer. The gas absorption capacity of the reservoir, gravitational differentiation, and miscible mass transfer were key factors affecting the migration of the oil–gas interface and distribution of the miscible zone. The entire displacement process could be divided into three stages: ① The gas-free rapid oil production stage, which was dominated by the displacement; ② the low gas–oil ratio stable oil production stage, which was jointly affected by the displacement and miscible mass transfer; and ③ the high gas–oil ratio slow oil production stage, which was dominated by the effect of CO2 carrying.

Oxidization characteristics and thermal miscible flooding of high pressure air injection in light oil reservoirs

Physical modeling, numerical simulation and field case analysis were carried out to find out the subsurface thermal oxidation state, thermal oxidation front characteristics and production dynamic characteristics of high pressure air injection thermal oxidation miscible flooding technology. The lighter the composition and the lower the viscosity of the crude oil, the lower the fuel consumption and the combustion temperature are. The thermal oxidation front of light oil and volatile oil can advance stably, and a medium-temperature thermal oxidation stable displacement state can be formed in the light oil reservoir under high pressure conditions. With strong thermal gasification and distillation, light oil and volatile oil are likely to form a single phase zone of gasification and distillation with thermal flue gas at the high-temperature and high-pressure heat front, finally, an air-injection thermal miscible front. In light oil reservoirs, the development process of high-pressure air-injection thermal miscible flooding can be divided into three stages: boosting pressure stage, low gas-oil ratio and high-efficiency stable production stage and high gas-oil ratio production stage. Approximately 70% of crude oil is produced during the boosting pressure stage and low gas-oil ratio high-efficiency and stable production stage.

Feasibility Study and Technical Optimization by Implementing Steam Flooding for the Field Development Plan of A Heavy-Oil Field in Yemen

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.

Evaluation of Chemical Application as Pilot to Improve Oil Production from High Viscous Oil in Sandstone Reservoir

Chemical injection stimulation is one of worldwide proven technologies for viscosity reduction and mobility enhancement. The principle mechanism is to reduce heavy oil viscosity by injecting of active chemical agent solution into reservoir as huff and buff practice, the agent solution is act at near wellbore area by remove plugging of heavy organic material, Energy support due to large quantity of stimulation liquid being injected into the formation, viscosity reduction by emulsification and micro-emulsion which will greatly enhance oil mobility; therefore, accelerate oil recovery and reduce interfacial tension (IFT); therefore, increase oil recovery. as global oil industry many technologies introduced to Sudanese oil fields such as chemical which had been implemented in 2018 to increase oil production by developing high viscous oil reservoirs. The pilot was done in two wells in Moga and Fula fields; they are located at southern part of western escarpment trend of Fula sub-basin, Main oil-bearing distributes in Aradeiba, Bentiu and Abu Gabra formations. Bentiu formation was selected for pilot, it is consolidated medium productive sand stone reservoir as per well test interpretation productivity index is 0.05 to 0.2 bbl/day/psia, PVT features: low bubble point pressure, low gas oil ratio (GOR), viscosity at initial pressure between 396–5902 mPa.s and 8986–13880 mPa.s at surface pressure and 29°C, permeability lab test results show strong heterogeneity formation. This paper discusses the chemical injection as enhanced oil recovery (EOR) application in block-6, investigate and evaluate pilot results, then discuss lesson learned from this pilot. Basic reservoir engineering principles and lab test result had been used to calculate production and reservoir parameters before and after implementation. The results of first well shows instantaneous downhole fluid level (DFL) raising about 129 m and remain stable while same pump speed was maintained after the chemical injection, the water cut dropped from 64% to 42% and Oil rate jumped from 95 BOPD to 204 BOPD. second well shows bad performance post the chemical injection and the oil rate decreased from 60 to 40 BOPD and WC increased from 70% to 93% due to well located in the down dip close to OWC and strong reservoir pressure support.

Experimental Study on Enhanced Condensate Recovery by Gas Injection in Yaha Condensate Gas Reservoir

A condensate gas reservoir is an important special oil and gas reservoir between oil reservoir and natural gas reservoir. Gas injection production is the most commonly used development method for this type of gas reservoir, but serious retrograde condensation usually occurs in the later stages of development. To improve the recovery efficiency of condensate oil in the middle and late stages of production of a condensate gas reservoir, a gas injection parameter optimization test study was carried out, taking the Yaha gas condensate reservoir in China as an example. On the premise that the physical experimental model and key parameters met the actual conditions of the formation, the injection method, injection medium, injection-production ratio, and other parameters of the condensate gas reservoir were studied. Research on the injection method showed that the top injection method had a lower gas-oil ratio and higher condensate oil recovery. The study of injection medium showed that the production effect of carbon dioxide (CO2) injection was the best injection medium, and the maximum recovery rate of condensate oil was 95.11%. The injection-production ratio study showed that the injection-production ratio was approximately inversely proportional to the recovery factor of condensate gas and approximately proportional to the recovery factor of condensate oil. When the injection-production ratio was 1 : 1, the maximum recovery rate of condensate oil was 83.31%. In summary, in the later stage of gas injection development of the Yaha condensate gas reservoir, it was recommended to choose the development plan of CO2 injection at the top position with an injection-production ratio of 1 : 1. This research can not only provide guidance for the later formulation of gas injection plans for Yaha condensate gas reservoirs but also lay a foundation for the research of gas injection migration characteristics of other condensate gas reservoirs.

Analysis of Lateral Fluid Gradients From DFA Measurements and Simulation of Reservoir Fluid Mixing Processes Over Geologic Time

Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.

Main controlling factors for the enrichment of shale oil and significant discovery in second member of Paleogene Funing Formation, Qintong Sag, Subei Basin

Based on the study of hydrocarbon generation features, oil bearing property and reservoir property of shale in the second member of Paleogene Funing Formation in the Qintong Sag of the Subei Basin, the main controlling factors of shale oil enrichment were analyzed. Shale of the second member of Funing Formation in the Qintong Sag was featured by large-scale thickness and medium TOC content, which provided a material basis for shale oil enrichment. The vitrinite reflectance (%Ro) of shale in the second member of Funing Formation in the deep sag distributed between 0.9%-1.0%, indicating a moderate thermal evolution degree. Shale oil has the characteristics of light hydrocarbon, high gas-measured total hydrocarbon value and good fluidity. Few faults were developed, resulting in good preservation conditions and high formation pressure, which were conducive to hydrocarbon enrichment. High content of brittle minerals and well-developed lamella and natural fractures made formation fracturing easier. The continuous and large-area distribution of high-quality shale is the basis for oil and gas abundance. Preservation condition is the key factor to reservoir formation. The degree of evolution is a decisive factor of oil-bearing. High pressure, lamina development and high brittle mineral content are important factors for high yield. The shale oil in second member of Funing Formation in Shaduo area has the characteristics of low TOC content (1%), low gas oil ratio (40-80 m3/t) and high pressure (1.25 MPa). The success of this well has reduced the shale oil evaluation standard and threshold, and expanded the development space of shale oil.

Selection of hydrocarbon gas for huff-n-puff IOR in shale oil reservoirs

In shale oil reservoirs, cyclic CO2 injection has proven to be effective at recovering significant amounts of oil, however, certain downsides to the use of CO2 exist owing to its corrosive nature and its higher miscibility pressure compared to hydrocarbon gases such as ethane and propane. This paper presents simulation results focused on the impact of phase behavior on the injection of single component gases such as; N2, CO2, C1 and C2, and a combination of hydrocarbon gases with varying C1, C2 and C3 compositions, as the basis for selecting an injectant, that is more effective than CO2 for cyclic gas injection.The simulations presented were carried out with rock and fluid properties from the Eagle Ford reservoir using Multi-Frac-Comp, an integrated Equation-of-State geomechanical compositional hydraulic fracturing and reservoir simulator (Zheng et al., 2019a, 2019b). Oil recovery results obtained for single component gas injection shows that C2 injection yields comparable oil recovery to CO2 and lower gas-oil ratio. Of all the injected gases, N2 yielded the lowest oil recovery and highest GOR because of its poor miscibility with the reservoir fluid. Simulations carried out using hydrocarbon gases with varying compositions of C1, C2 and C3 show recovery factors that are higher than C2 injection. The results show that hydrocarbon gases with a higher C1 content over C2, results in faster oil recovery during the initial cycles of huff-n-puff because the high compressibility of C1 enhances the volume expansion obtained upon depressurization during the production phase. In contrast, HC gases with higher C2 and C3 content yield higher recoveries during the later cycles because the high density of these gases improves miscibility with the reservoir fluid during the soak phase.The results from this study provide operators with information required to select a hydrocarbon gas with an optimum composition of C1, C2, C3 and C4. This strategy of tuning the injected fluid composition during different cycles of gas injection can play an important role in improving oil recovery from huff-n-puff field pilots.

Comparative numerical study for polymer alternating gas (PAG) flooding in high permeability condition

Polymers have been used in water alternative gas, to viscosify the water and improve the overall sweep efficiency. The use of polymer alternative gas was successful in increasing the oil production in high permeability zones. However, few practical factors affecting the field applicability have been overlooked. Therefore, this study is aimed at bridging the gap between the possibility of using several EOR such as water flooding, CO2 flooding, water alternative gas, polymer flooding and polymer alternative gas. The research based on progressive comparison considering constant constraint. The numerical simulation STARS-CMG was used to predict the characteristics and behaviour of the fluid in the reservoir. The designed flooding pattern chosen was a single producer-single injection (P-I) scheme in homogeneous high permeable reservoir. The results of oil incremental recovery showed the following order compared to Water flooding < (3%) CO2 flooding < (6.8%) < Water alternative gas (11.6%) Polymer flooding < (15%) Polymer alternative gas. The impact of polymer on enhancing the water alternative gas was mostly noticeable in the reduction of water cut% (83%). The controlled conformance by polymer aided in improving the sweep efficiency as indicated by the uninform U-shape. Moreover, the delayed gas breakthrough was significant and resulted in the lowest gas oil ratio of 5.17E + 04 ft3/bbl. The low gas oil ratio observation is indication of potential capturing of CO2 in the reservoir and thus, good evidence to further implementation of CO2 as green utilization.

Natural gas underground storage and oil recovery with horizontal wells

In this research study a reservoir simulation is conducted to compare the performance of the wells in a depleted oilfield for Enhanced Oil Recovery (EOR) and subsequent Underground Natural Gas Storage considering different well profiles including vertical and horizontal trajectories. The underground gas is simulated to be stored at an increasing reservoir pressure up to a magnitude that is to 85% of the initial pressure, and reservoir pressure remains constant throughout. The results of the simulations reveal more oil which can be potentially recovered by means of developing the field with horizontal wells. The extended component transformation between the oil and gas phases, additional viscosity reduction in oil phase, low gas oil ratio, and favoring bottomhole pressures attained by means of horizontal wells has shown to be considerably effective for EOR and underground storage applications.

Experimental Study on Factors Affecting the Performance of Foamy Oil Recovery

The flow characteristics of dissolved gas driven processes in some heavy oil reservoirs, such as low gas–oil ratio and higher oil recovery rate than expected, are quite different from conventional oil production processes. Foamy oil is considered one of the main reasons behind such a production phenomenon. In this paper, the factors affecting the performance of foamy oil recovery were experimentally investigated in a sandpack medium with the assistance of computed tomography (CT) technology to help further the understanding of the mechanism. Five different experiments were applied and the results showed that (1) the linear pressure drop production model had a similar oil recovery to that of the step-down mode; (2) increasing the depletion rate could be more favorable to the oil recovery rate; (3) under a constant gas–oil ratio, raising the temperature had little impact on oil recovery, but showed obvious impact on the production curve; and (4) with higher permeability, there were more residual oil at the end of the displacement process. Lastly, a dry gas huff and puff experiment was conducted and the decreased oil saturation was observed in the inlet section, while no obvious effect was remarked in the outlet region of the medium.

The Discovery and Development of Oil Rim Fields in the Beibu Gulf, China

The Beibu Gulf is a prolific hydrocarbon province on the western coastline of China. The Miocene Jiaowei Formation contains thick sandstone sequences with excellent reservoir quality, a low degree of internal heterogeneity and excellent aquifer support. Structures are low relief causing many discoveries to be classified as thin oil rim fields (<15m oil columns with bottom-water drive). These discoveries have moderate to heavy oils with low gas-oil ratios and moderate to high oil viscosities. The combination of these rock and fluid properties are ideal conditions for rapid water coning, hence early well water breakthrough and low oil recovery factors. However, multiple fields in the Beibu Gulf significantly exceed pre-development production expectations. Closer inspection of core and log data indicates there is often a dolomitic alteration zone at the oil-water contacts with permeabilities typically 2 to 3 order of magnitudes lower than the hydrocarbon-bearing reservoir which act as effective aquitards to slow the onset of water breakthrough. The diagenesis is theorized to be due to microbial decomposition of hydrocarbons at the oil-water interface which accrete dolomitic cements as a by-product. Seismic inversion and amplitude mapping reinforce the view that the alteration zones are pervasive and flat-lying. Case studies are presented covering the discovery, development and production performance of three oil rim fields in the Beibu Gulf.

The Experimental Study on the Flooding Regularities of Various CO2 Flooding Modes Implemented on Ultralow Permeability Cores

The application of water flooding is not successful for the development of low permeability reservoirs due to the fine pore sizes and the difficulty of water injection operation. CO2 can dissolve readily in crude oil and highly improve the mobility of crude oil, which makes CO2 flooding an effective way to the development of the ultralow-permeability reservoirs. The regularities of various CO2 displacement methods were studied via experiments implemented on cores from Chang 8 Formation of Honghe Oilfield. The results show that CO2 miscible displacement has the minimum displacement differential pressure and the maximum oil recovery; CO2-alternating-water miscible flooding has lower oil recovery, higher drive pressure, and relatively lower gas-oil ratio; water flooding has the minimum oil recovery and the maximum driving pressure. A large amount of oil still can be produced under a high gas-oil ratio condition through CO2 displacement method. This fact proves that the increase of gas-oil ratio is caused by the production of dissolved CO2 in oil rather than the free gas breakthrough. At the initial stage of CO2 injection, CO2 does not improve the oil recovery immediately. As the injection continues, the oil recovery can be improved rapidly. This phenomenon suggests that when CO2 displacement is performed at high water cut period, the water cut does not decrease immediately and will remain high for a period of time, then a rapid decline of water cut and increase of oil production can be observed.

Short-term model-based production optimization of a surface production network with electric submersible pumps using piecewise-linear functions

This paper describes the development details and results of a model-based production optimization scheme to advice how to set frequencies of electric submersible pumps to maximize total oil production in a surface network. Furthermore, the effect of model fidelity and modifications to enforce high ESP efficiency are studied. The particular system targeted is surface networks with ESP-lifted wells, high water cut, low API gravity and gas oil ratio where wells require regular updates to their frequencies and there are multiple operational constraints.The model employed for the optimization is a steady-state synthetic surface network with 15 wells. The optimization is formulated as a Mixed-Integer Linear Problem by approximating the network model using piecewise linear functions (tables). Well opening and ESP frequency are the two controllable variables. Monte Carlo simulations were performed varying randomly the predicted pressure drop in each pipe section within 20%. The operational envelope of the ESP was reduced to enforce high pump efficiency.For the cases tested the optimization methodology has low runtime (13 s avg.), reproduces with an acceptable accuracy (average 0.6%, maximum 5%) the original network model, it handles successfully multiple operational constraints and guarantees global optimality. Additionally, it can be easily updated to reflect depletion changes by generating new tables. Monte Carlo simulations show that model fidelity has a minimal effect in the variation of the optimal conditions found. The modifications to enforce high ESP efficiency reduce significantly the maximum oil production predicted (37%).

Studies on the Stability of the Foamy Oil in Developing Heavy Oil Reservoirs

In the process of natural energy depletion, foamy oil is characterized of low production Gas Oil Ratio, high oil viscosity, high daily production rate and high primary recovery factor. The stability of the foam turns out to be the prevailing factor that governs the life of the ‘foamy oil’. To enumerate the main factors affecting the stability of the foam, a high-temperature–high-pressure visualized experiment model for foamy oil stability test was developed. A serial of experiments was conducted to evaluate the performance of the foam stability. The effects of oil viscosity, height of the oil column, dissolved gas content and dispersed gas were investigated and recorded. These experiments were conducted using a Hele-Shaw, a high pressure cell. The volume of foamy oil produced, either by a step reduction in pressure or by a gradual (linear) reduction in pressure, and its subsequent decay was observed, visually. The experimental results show that foamy oil stability increases with higher oil viscosity, higher oil column, higher dissolved gas content and higher pressure decline rate. Asphaltene content was not observed to increase the foamy oil stability significantly. The results also show that the foam quality of foamy oils is much lower than aqueous foams.

Spatial Analysis of Horizontal-Shale-Well Water Production in the Wattenberg Field

Summary Reusing waste water from the oil field for hydraulic fracturing has become an important topic in the oil and gas industry, and it requires a thorough understanding of both the quality and quantity of the waste water. In this paper, water production from horizontal shale wells in five sections of the Wattenberg field in northeastern Colorado was analyzed. Models were developed for these wells for future water-production prediction. A spatial analysis was also conducted by comparing water production from each section with the gas/oil-ratio (GOR) value for each well. Results indicate that the GOR value of wells has a significant impact on water production in the first year of operation. Wells with low GOR value tend to have higher fracturing-flowback volume and, furthermore, water-recovery rate. Results from this study also provide valuable information for estimating water production from unconventional shale fields, which is critical for the design of wastewater collection and treatment facilities in the field.