Abstract After more than 20 years’ development, S oilfield has entered high water cut stage. The layer contradiction is prominent and the water flooding condition is complex, which result in the complex decentralized state of the remaining oil. In order to determine the remaining oil distribution to guide the comprehensive adjustment of the oilfield, the reservoir architecture analysis of delta front was conducted. Based on the core, seismic data, dense well logging data and production performance data, the reservoir architecture of delta front in Dongying group is characterized with hierarchy process, model guidance and numerical simulation methods. In the paper, the distribution style of interlayers in single mouth bar is discussed. The distribution feature of the remaining oil under the control of interlayers is analyzed. It shows that multiple main channels form continuous mouth bar complex and single mouth bar develops several accretions. Interlayers in single mouth bar express in two forms: the foreset type along the source direction and the arch type perpendicular to the source direction with a low angle from 0.4° to 1.0°. Along the source direction, remaining oil gathers inside accretions whose injection-production does not correspond under the control of interlayers. And the remaining oil is enriched at the front of accretion. In the vertical source direction, the remaining oil accumulates in the high part of accretions. Under the guidance of remaining oil distribution characteristics controlled by reservoir architecture, one horizontal well was deployed. The average output is more than 100m3/d and the water cut is under 30%, which indicates the effect of this reservoir architecture analysis work. The successful implementation of the horizontal well demonstrates the vital function of the reservoir architecture research for this kind of mature oilfield. This will also be one promising research direct for the overall adjustment and remaining oil tapping.
Abstract In bohai offshore oilfield, about 98% oil wells produce with electric submersible pump (ESP). For the common ESP system, workover is needed to replace the failed pump about every 4 years, resulting in significant operation cost and production lost. To solve this problem, a new type of rigless fully retrievable electric submersible pump (RFR-ESP) is developed and applied in bohai oilfield. This paper mainly introduces the technical details of the used RFR-ESP system, and the real application effects in typical wells. This new system consists of downhole permanent part and retrievable part, with the power cable clamed externally along with the tubing. The core of the system is a specially designed wet connector system. Through this connector, any ESP manufacture's equipment can be used. For this technology, the retrieval of ESP can be finished by standard oilfield wireline operation, and no rig workover is required any more. Till now, two different systems suitable for 7″ tubing and 5-1/2″ tubing have been developed in order to meet the yield of different wells. Bohai oilfield installed the first RFR-ESP in 2013. Up to now, 6 wells have applied this technology, including one water source well and five oil wells. The longest running time of the ESP is about 2000 days, and it is still in service now. The maximum liquid production is about 2800m3/d. For this new system, the workover time of ESP replacement reduces from 10 days to about 2 days comparing to the traditional rig workover process, and the number of the workover operators reduces from 30 to about 10. All of these are helpful to reduce the workover cost and the production lost. Besides, several problems encountered in the wells, such as power cable failure provides valuable field experience for the promoted application in bohai offshore oilfield. The successful application of this technology indicates that it has the potential to lower ESP operating costs, and even improve the artificial lift status of offshore oilfield. What's more, this new system is expected to be used in unmanned platform, thus no workover boat is needed any more, which will drastically cut down the development cost.
Abstract This paper introduces a new water controlling technology to manage water production and improve production performance in an offshore oilfield in Bohai, China. Q oilfield is a typical heavy oil reservoir, mainly developed by horizontal wells. One of the main challenges for the production is the high water cut. Most of the wells experience water breakthrough within one year after put into production and produce for long time with water cut higher than 90%. Besides, the strong anisotropism of the formation aggravates the water breakthrough and makes water control work more difficult. In 2019, a new combined water control technology was applied to manage water influx in horizontal completions. In this technology, the annulus between the wellbore and the inner ICD (inflow control device) /AICD (Autonomous inflow control device) screen is filled with light-but-hard particles. In this paper, the barrier built by the fine particles is called continuous-packer. The existence of this barrier plays a similar role to mechanical packers between each ICD/AICD screen, thus the axial flow of the produced liquid is prevented in the horizontal section. Besides, the ICD/AICD screen is equipped to limit the liquid inflow of each segment based on the design. The purpose of equalizing production profile of the horizontal section achieves through the cooperation of the continuous-packer and the ICD/AICD screen. Untill now, this new technology has been used in more than 6 wells in Q oilfield, including both producing horizontal wells with high water cut and newly drilled wells. The production results show that the water cut reduces about 10% and the oil production increases for the high water cut well. The water breakthrough time and the water cut increasing rate is slower for the new wells comparing with near wells. The successful application of this technology demonstrates its validity for the offshore heavy-oil reservoir with active bottom water. It also provides a new method for the water controlling work for the offshore wells in Bohai oilfield. A detailed plan has been finished to implement this technology in more wells in 2020.
Abstract The hollow rod electric heating (HREH) technology can greatly increase the temperature of the fluid in wellbore and improve its fluidity, which is widely used in rod pump wells. Bohai offshore oilfields also have urgent application requirements for HREH technology due to the wide distribution of heavy oil and high waxy crude oil. However, more than 90% of the oil wells there are produced by electric submersible pumps (ESPs). None of these christmas trees in use are suitable for ESP wells using HREH technology. Based on the conventional christmas tree with only one main channel, a new type of eccentric christmas tree, with separated main channel and cable channel, is designed. As with the conventional ones, the main channel works as the flow passage of wellbore fluids. And the cable channel is used to run and pull out the heating cable. The eccentric design of the main channel provides the space for the cable channel. The separate cable channel avoids the cable crossing the main channel, so that the master valve of the christmas tree can be opened and closed normally, which contributes to ensuring safe production. In the meanwhile, the christmas tree can also seal the heating cable owing to some special design. This new device has been successfully tested on 6 ESP wells in Bohai Bay. After the installation of the christmas tree, the cable was smoothly run down to the predetermined depth. The construction operation was simple and convenient. There was no oil or gas leakage at wellhead after it was put into use. The wellhead temperature of all these wells reached above 50°C and no wax deposited in tubing any more, verifying its safety and reliability. This new type of safe and reliable christmas tree lays a solid foundation for the popularization and application of HREH technology, especially in those waxy oil wells and heavy oil wells with ESPs.
Abstract There is abundant heavy oil resource in Bohai Oilfield and thermal recovery is an effective method to realize the high-efficient development. Till now, several field pilots have been conducted. However, for the offshore thermal recovery well, the onshore common used rod pump artificial lift technology is not applicable. The ordinary electric submersible pump (ESP) system cannot be directly used either, because it cannot stand the high-temperature steam. Therefore, artificial lift technologies suitable for offshore thermal recovery well is developed in recent years. For the ESP system, a high-temperature safety control system was developed, consisting of downhole safety valve, cable packer, and vent valve. The overall temperature and pressure resistance value could reach as high as 350°C and 21MPa, respectively. And the high temperature electric submersible pump could stand 250°C cyclic steam. This ESP system has been used in about 30 thermal recovery wells in Bohai Oilfild, satisfying the artificial lift requirements for the moment. With this ESP system, the overall process of each huff-and-puff cycle includes: lowering steam injection tubing, steam injecting, soaking, replacing production tubing, producing. That means two workover operations for tubing changes are required in each huff-and-puff cycle, which adds more cost to the oil production and has bad effect on the thermal recovery. Considering the drawbacks of the current ESP system, a new concentric-tubing jet pump system suitable for offshore oilfield with function of both steam injection and oil production is developed. Besides, the matched surface equipment, such as oil-water-sand separator and power fluid pump, are designed. The temperature resistance of the designed jet pump system reaches 400°C. With this system, no workover for tubing replacement is needed any more during one huff-and-puff cycle. Till now, this new jet pump system has been put into field pilot in one thermal recovery well. Both the steam injection and oil production process completed successfully, indicating its applicability for the offshore thermal recovery wells. In this paper, the tubing string structure details of the jet pump system and the specific field operation process is introduced. This new artificial lift technology will be gradually applied in other wells to improve the thermal recovery effect because of its advantages comparing with ESP system. Great progress and breakthrough of the artificial lift technologies suitable for offshore thermal recovery have been achieved in recent years in Bohai Oilfield, which will provide powerful technical support for the high efficiency development of the heavy oil resource in Bohai Bay.
Abstract This paper proposes an integrated technology of chemical sand control and stratified water injection in water injection well, which enlarge the inner diameter of injection well after sand control and achieve flexible stratification of injection layer. Mechanical sand control is the main method for injection wells in offshore oilfields. After sand control, the inner diameter of injection well is small and the number of injection layers is generally 3-4 layers. For reservoirs with strong longitudinal heterogeneity, it's difficult to get higher longitudinal sweep coefficient of driving and better effect of injection. The technology realizes completion by chemical sand control, without screens downhole. The ceramsite whose surface has been treated by crosslinking agent is injected into the well and heated. The crosslinking reaction occurs on the surface of the ceramsite, forming a cement layer with a thickness of 3-5cm and a certain compressive strength of 7.2MPa and a permeability of 5000mD on the wellbore. This cement layer not only can be used as a barrier to retain formation, but also can provide flow channels for fluids. Then, the stratified injection pipe string is run. The developed multi-functional packer contacts and seals the cemented layer to realize the stratification of the injection reservoir. The position and quantity of the packer are designed according to the target injection horizon to achieve flexible stratification. This technology has been successfully applied to 4 wells in the Bohai Oilfield, all of which have the characteristics of large reservoir thickness and strong vertical heterogeneity. The conventional sand control and injection technology makes it difficult for the actual injection volume to reach the target volume, and the water cut of the benefit well continues to rise. After applying the integrated technology, for a directional well with a bore diameter of 9.625 in, the maximum inner diameter can reach 9.625 in, while the inner diameter of traditional sand control methods is only 4.75 in. The number of injection layers exceeds 5, and the actual injection volume meets the designed requirement. The validity period has exceeded 40 months and continues to be effective. The water cut of the benefiting well decreases from 85% to 78%, and the oil production rate increased from 56 m3/d to 72 m3/d. The successful application of the integrated technology provides a new idea for subdivision water injection in offshore oilfields. The increase in the internal diameter of well can reduce the difficulty of operation and increase the water injection rate. The flexible stratification can improve the vertical production degree of reservoir water flooding and the overall effect of water injection.
Traditional fault seal analysis requires deterministic structural and stratigraphic models and significant fluid flow data for transmissibility calibration. For multi-faulted reservoirs with large structural and stratigraphic uncertainties and little dynamic data, traditional method fails to capture the range of production scenarios. This paper proposes a new method to capture the range of possibilities via stochastic analysis in juxtaposition, shale gouge ratio, and fluid flow. First, we gather the stratigraphic and structural information and generate the parameter ranges, such as reservoir layer thicknesses, net-to-gross ratio, number of layers, etc. Then, many juxtaposition realizations are created from these parameters. When reservoir zone thickness is greater than the fault throw, the shale gouge ratio is reduced to a function of net-to-gross ratio alone. Afterward, we construct the probability distribution function of cross-fault transmissibility by combining juxtaposition, shale gouge ratio and dynamic data. Finally, the transmissibility probability is provided to the simulator for reservoir performance simulation. This procedure has been applied to the appraisal of an offshore oil field that has many faults and subseismic reservoir layers. The procedure is demonstrated in 1D but can be expanded into 3D by allowing the controlling parameters to vary with location.<br>
Horizontal wells are widely applied in the Bohai offshore oil fields due to their large oil drainage areas and high yields. However, water coning is a significant problem existing in water-driven reservoirs. To control water coning, this paper introduces a stinger completion method which can be applied in the horizontal wells. Based on the principle of mirror reflection and mass conservation law, a mathematical model coupling fluid flow both in the reservoir and in the horizontal wellbore has been developed. Using the new proposed model, the well production profile and bottom hole flowing pressure distribution along the horizontal well, considering the influence of flowing in the wellbore, are calculated successfully. Moreover, the influence of the stinger completion on the inflow profile is investigated. According to the results of the sensitivity analysis, a 160 m' 2-7/8 tubing is designed to be built in the horizontal section. The field-test results show that the stinger completion could be used to improve the wellbore inflow profile and decrease the possibility of water-cut thus increasing the effective enhanced oil recovery (EOR). Cited as : Shang, B., Han, X., Li, S., Liu, K. Research of water control technology for horizontal wells in water-driven reservoirs. Advances in Geo-Energy Research, 2018, 2(2): 210-217, doi: 10.26804/ager.2018.02.08
Abstract Inflow Control Device(ICD) is considered to be an effective water control technology, especially in offshore reservoirs with strong bottom water, which is more conducive to slowing water breakthrough, increasing recovery factor during low water cut period, reducing produced water treatment costs and improving development effect. The H oil field in Bohai Bay, China is a target oil field where horizontal wells are widely used by traditional ICDs. The characteristics of the H field are heavy oil (average viscosity of 260 mPa·s under reservoir conditions), excellent reservoir quality (up to 30% porosity and 3D permeability), loose sand, heterogeneity and strong aquifer. In the process of water control in horizontal wells, the sand channeling and annulus channeling outside the sand control screen were the main factors that caused the water control failure by early ICDs. In the later design and application, the ideas and methods were improved. Based on the review of the conventional ICD application, a new work-flow was proposed to design and to optimize the ICD to improve the opportunities for success and to prolong the effective water control period. Compared with the previous design ideas, more attention was paid to the segmentation and environmental control isolation methods: In the case of reservoir heterogeneity uncertainty, increasing the number of segments and uniform segmentation is more conducive to accurate plugging and release potential. The most ideal condition is continuous step-less isolation. A new type of lightweight, high-strength, and easy-to-carry particles were used to fill the environmental control with high strength, which results in a step-less continuous horizontal sealing effect while preventing sand production. The particle filling volume and particle radius can be adjusted. The size of the particle radius determines the additional pressure drop of the loop control zone, and the filling volume determines whether the loop control channeling is completely avoided. The improved ICD completion device had been successfully applied in 4 production wells in the oil field. The water cut of the well dropped by 10%, and the initial daily oil production increased by 145 barrels. This result greatly inspired our confidence. In the future plan, we are willing to adopt the plan to control water in 12 wells in two batches. And due to the improvement and quality control of key links in the design and process, implementation time have been significantly saved which is extremely important for offshore platforms to obtained good economy returns. This article proposes a detailed, complete, and smooth work-flow, including actual oil field information, target well selection, segmentation method, fill volume estimation and implementation effect evaluation. This work-flow has great reference value for industry peers to improve the efficiency and quality control of hybrid ICD projects.
The Chinese government is seeking CO2 gas emission reduction measures. CO2 capture and geological sequestration is one of the main measures. Injecting CO2 into oil reservoirs can not only achieve the environmental protection purpose of CO2 geological sequestration but also improve oil recovery and realize economic benefits, which helps to offset the cost of CO2 sequestration. Therefore, the oil reservoir is one of the best sites for CO2 sequestration. As for the reservoir of CO2 flooding after water flooding, there are two methods for evaluating the potential of CO2 enhanced oil recovery (EOR) and sequestration capacity, which are the mass balance method and analogy method. Through a combination of these two methods, this paper presents a new method, which can be reasonably used to evaluate these potentials. Besides, the screening criteria of CO2 sequestration and EOR in the Junggar Basin are also proposed. On the basis of the guidelines of CO2 source matching, reservoir characteristics, and fluid characteristic, four typical low permeability reservoirs (Caiman oil reservoir, Karamay oil reservoir, Beisantai oil reservoir, and Luliang oil reservoir) of the Junggar Basin are selected to study their potential of CO2 EOR and sequestration. And then the potential of CO2 EOR and sequestration capacity for the Junggar Basin oil reservoirs of CO2 flooding after water flooding is studied by applying the method mentioned above. For 275 development blocks of 24 oil fields in the Junggar Basin, 139 development blocks are suitable for CO2 miscible flooding EOR and sequestration, whereas 136 development blocks are suitable for CO2 immiscible flooding EOR and sequestration. The total EOR potential could be 18 407.76 × 104 t and the CO2 sequestration potential could amount to 47 486.0 × 104 t. The evaluation results show that the Junggar Basin's oil reservoirs are suitable sites for CO2 EOR and sequestration and have great potentials. It can provide the decision basis for the future implementation of CO2 emission reduction projects in Western China.
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