The development of a new low-carbon operation mode of artificial lift in high-water-cut oilfields, is significant for reducing energy consumption, improving operation efficiency and lowering production costs of oilfields. The annual electric consumption of the oilfield is increasing year by year. In 2016, the total electric consumption exceeded 35 billion kWh, of which the mechanical production system accounts for 57%.
The rodless artificial lift eliminates the use of the sucker rod, and reduces the installed motor power over 50%. The electric consumption is greatly decreased, while tremendous gain is seen in the system efficiency. Moreover, the application performance is especially good for low-production wells. Under such circumstances, the operation cost of the oilfield declines. The current rodless artificial lift is basically based on two types of pumps, namely submersible plunger pump and submersible direct-drive screw pump.
The submersible plunger pump lifts liquid via vertical reciprocation of the moving body driven by the motor, with daily electric consumption of an individual well decreasing by 46%, from 133.4 kWh to 72.5 kWh. The reduced annual electric cost per well is RMB 14,000, and the annual single-well carbon emission falls by 17.5 tons. As for the submersible direct-drive screw pump, the rotation of the pump is directly motivated by the downhole submersible motor, through which the downhole liquid is elevated to the surface. The daily electric consumption of an individual well decreases by 38.4%, from 224kWh to 138kWh, contributing to the annual electric cost reduction per well of RMB 13,600 and annual carbon emission decline per well of 17.1 tons.
The application of the two types of rodless artificial lift has taken initial shape. The submersible plunger pump has been applied to over 200 wells, and the submersible direct-drive screw pump, over 60 wells. The new low-carbon operation mode of artificial lift is critical for the energy saving, efficiency improvement and consequent cost reduction of oilfields, particularly in cases of the industry downturn triggered by low oil prices.
In 2008, We presented a paper "Application of Temperature Observation Wells during SAGD Operations in a Medium Deep Burial Extra Heavy Oil Reservoir" at the Petroleum Society's 59th Annual Technical Meeting. After 10 years SAGD technology is already widely adopted in exploiting extra heavy oil in China. This paper summarizes the experience on surveillance of SAGD project in the past years.
During SAGD process the adjustment of steam chamber in both vertical and horizontal direction and operation parameters should base on synthetic surveillance data. In the past, the surveillance approach is very limited and the results cannot be used as effective indicators. The successful application of reservoir based synthetic surveillance approach produced reliable data for management of SAGD project in Du 84 block Liaohe Oil field. The applied technical series include pressure/temperature observation wells, pressure/temperature monitoring in horizontal wells, time-lapse seismic monitoring, micro-gravity test etc. With the help of these monitoring data, the accurate and long term effective database was established.
The application of synthetic monitoring system provides the opportunity of accurate control of steam injection and production. The temperature and pressure observation well can monitor the vertical development of steam chamber, especially in gas-SAGD process. The observation well can detect the vertical sweep area of injected gas which can give effective approach in SAGD management. The temperature and pressure monitoring and tracer test can provide information for connection between injector and producer. 4-Dimensional seismic and 4-Dimensional micro gravity is a new approach of combination for petro-physical technology and petroleum development. 4D seismic not only can remap the geological body but also it can depict the steam chamber distribution in the reservoir. 4D micro gravity monitoring can accurately detect the front of steam chamber. With these data, the distribution of steam zone and residual oil is clear for future reservoir management.
This paper gives a verified approach of surveillance and the corresponding operation adjustment. And this can be guidance for design and application of new SAGD surveillance system.
Liu, He (RIPED, CNPC) | Zhang, Shaolin (RIPED, CNPC) | Sun, Qiang (RIPED, CNPC) | Li, Tao (RIPED, CNPC) | Ming, Eryang (RIPED, CNPC) | Huang, Shouzhi (RIPED, CNPC) | Han, Weiye (RIPED, CNPC) | Chen, Qiang (RIPED, CNPC) | Li, Yiliang (RIPED, CNPC) | Pei, Xiaohan (RIPED, CNPC)
After long-term water-flooding, many of the matured fields in China have experienced changes in the physical properties of reservoirs. Moreover, the inefficient cycle of water flooding in the reservoirs is serious, and the heterogeneity of reservoirs causes difficulty to determine the distribution of remaining oil. It is impossible to reflect the real situation of the stratum only by simulation analysis with the numerical simulation software. To core in a specific location through coring technology and analyze the core can not only re-conduct a more accurate evaluation of the stratum, but also can modify relevant data of existing models to improve the simulation accuracy. But the current technology can’t conduct coring operations near wellbore and in deep parts.
Therefore, based on the ultra-short radius sidetracking technology, this paper aims to develop ultra-short radius flexible sealed coring technology to achieve coring outside the casing. Compared with the ultra-short radius sidetracking technology, the ultra-short radius flexible sealed coring technology has, in addition to the windowing, deflecting, and horizontal drilling tools, the core tools of this technology, that is, the flexible sealed coring tool. The tool is mainly composed of a flexible outer cylinder and a highly elastic titanium alloy inner cylinder. The flexible outer cylinder is connected by a multi-section of flexible units that can be bent up to 5°. And a special coring bit is connected to the front of the tool. The maximum length of the core taken in a single coring process is 1.1 meters; the core diameter is up to 40mm. By using this technology, the minimum horizontal distance of the core position and the borehole wall is 0.8 meter, and the maximum horizontal distance can be up to 100 meters.
At present, the technology has been successfully applied to more than 10 wells, and the average core recovery rate has reached 90%, which provides valuable data for the geological departments and is of great significance for re-developing matured fields.
This technology can obtain the core from outside of the casing and near wellbore, and offers a more accurate evaluation on changes of physical properties of the reservoirs, providing the basis for adjusting the subsequent water flooding development plans.
This paper demonstrates successful application of parallel appraisal and development in G field, Niger. G field is a complicated stacked light oil reservoir with gas cap in its E2 major pool. After current operator's takeover in 2008, the government required realization of 10 KBOPD in this field within 3 years, leaving only 1 year for appraisal and development as field construction in this landlocked country at least takes 2 years. Whereas there was only 2D seismic and one well data (G-1) with RFT and testing, parallel appraisal and development strategy must be adopted and following 2 major challenges were identified: 1) Limited data and great uncertainties in gas-cap and well productivity; 2) development decision-making along with appraisal process.
Appraisal and development have been optimized by following approaches: 1) RFT and wireline data were fully studied to identify oil-gas-contact in E2 pool and indicate possible oil in E3 pool; 2) appraisal wells placement based on new 3D seismic; 3) identify key uncertain development parameters and combine into appraisal campaign targets to gradually reduce uncertainties.
Appraisal well G-2 confirmed the separation of block G-1 and G-2. The second appraisal well G-3 confirmed oil-gas-contact, encountered oil zone in lower E3 pool. The third appraisal well G-8 encountered oil zone in E2 and further firm up gas-cap area, laying firm foundation for subsequent development well placement.6 producers were placed out of gas cap and appraisal wells were transferred to development wells, all successfully commissioned in 2011, achieving desired production target.
Conclusions drawn from successful parallel appraisal and development application were:1) utilization of all data available contributed to correct appraisal decision-making; 2) Combining 3D and appraisal well findings help reduce geological uncertainties; 3) Identify and reduce key development uncertainties during appraisal speed up appraisal process. For complicated fields at appraisal stage, the methodology in this paper is of strong reference value.
The technological advances for fracturing and horizontal well makes it viable to achieve unconventional hydrocarbons reserves developing commercially. Underground water, soil and environmental protection are currently major issues when unconventional hydrocarbons extracted. Liquid CO2 fracturing instead of the hydraulic fracturing for oil field stimulation is an effective way for water resource protection, pollution reduction, greenhouse emission reduction.
According to the current technologylever, liquid CO2 fracturing cannot reach the same fracture generation ability as the conventional fracturing, so the approach has been proposed and implemented to collaborate fracturing and pressure support to improve production performance by liquid CO2 injection in the low-permeability reservoir. An important part of the approach is that significant amount of injected CO2 is dissolved in remaining oil, similarly CO2 huff-puff, contributing to oil recovery enhancement, some will beproduced and needed to be cycled.
The methodologyis proposed in this paperto obtain the volume of CO2 storage at different fracturing scales for liquid CO2 fracturing by employing thecompositional simulation in low-permeability reservoir in Jilin Oilfield. A high-resolution geological model based on geological, geophysical, production and liquid CO2 fracturing data from H Block in Jilin Oilfield is usedin the study. The dynamic model is calibrated to the reservoir's history performance as a benchmark for the study. Several models represented the different fracturing scales are generated and the storage capacity is analyzed as a function of CO2 injection volume, soak time, pressure and oil productivity.
The study data show that the CO2 storage volume decreases as the length and conductivity of fracture increases. As a result, CO2 storage ratio is 0.218 if fracture with half length is 100m and permeability is 100md, CO2 storage ratio is 0.67 if no fracture exists. This goes toward creating gas separation and recycling injection device for large-scale liquid CO2 fracturing concerning CO2 zero emission.
The research has been noteworthy in its explicit recognition of the need for CO2 recycling during liquid CO2 fracturing by simulation of CO2 storage capacity. Pressure swing adsorption method will be introduced by great change of CO2 concentration of the produced gas from the simulation result.
10 typical Surfactant-Polymer (SP) flooding field tests in China were reviewed to help understand the benefit and challenge of SP flooding in low oil price era. Among these 10 field tests, only 2 were very successful, the others were not as good as expected, while some are technically and economically unsuccessful. Although ASP flooding can make incremental oil recovery of 30% in large scale field tests in Daqing, the complex anti-scaling and emulsion breaking technology and thus high cost makes it less attractive. No alkali SP flooding was believed a developing trend of chemical flooding with a predicted incremental oil recovery more than 12%. In this paper, 10 large scale SP flooding field tests including one in offshore in China were critically compared and reviewed. Surfactants and its screening techniques were introduced. The problems of high injection pressure and difference to predicted incremental oil recovery were discussed. Although laboratory tests showed that SP flooding could make additional recovery of more than 15%, and the predicted incremental oil recovery was between 12% to 15.5%, only one SP flooding in Shengli made high incremental oil recovery of 16.8% upon water recovery of 36.3%. This field test was so successful that many enlarged field tests and industrial applications were carried out. However, none of them was in agreement with numerical simulation. The actual incremental recovery was in 1.3%-6.7%. Incremental oil recovery in post– polymer flooding reservoir in Daqing was 2.4%, less than the expected value 6.3%. Recently 3 of 5 field tests in Xinjiang, Jilin and Changqing was far from success. Three reasons may account for this. First, the surfactants adsorption in formation makes the ultra-low IFT duration not as long or far as expected, as verified from both laboratory and field test. Second, the injected polymer concentration and molecular weight was too high for the reviewed reservoir formation. SP field tests results in high permeability Liaohe reservoir was much better than the other 4 field tests in CNPC. Third, resent screen method and numerical simulation technique needs to be improved since most field tests results were in disagreement with them. It is high time to reevaluate the potential of SP flooding. It is high time to study how far the ultra-low IFT chemical system can flow in reservoirs. Low adsorption surfactants were the key to success for SP flooding. The alkali effect in ASP flooding should have been more emphasized and investigated.
This paper demonstrates an innovative clusterization approach to define development strategy for small and scattered fields in T Basin, which is located in landlocked central Africa. As a rifted basin, T basin is around 250 km long and 80 km wide under sub-Saharan desert environment. The operator started exploration in 2008 and had discovered over 40 oil fields scattered over the whole basin but with limited size. 30 small oilfields occupy only 20% of total OOIP. Therefore the discovered fields in T basin belong to small and scattered fields. To realize fast track development in landlocked desert and achieve economic robustness meanwhile is the huge challenge for the operator. Clusterization development strategy had been put forward to realize integrated asset development.
Clusterization is to define several oil field clusters based on the criteria of adjacency, reservoir characteristics etc. Each oil field cluster should have one and/or two relatively bigger oil field as the central fields. Satellite fields are grouped into adjacent central fields thus forming oil field clusters. The whole basin development optimization could be carried out on a two-tier level: 1) for the intra cluster level, central fields will be commissioned first and satellite fields could be ranked to substitute production plateau, satellite fields facilities could be skid-mounted and shared among satellite fields to reduce Capx. 2) for the oilfield cluster level, clusters could be ranked according to criteria of OOIP scale, productivity projection and commissioning complexity. Relatively concentrated oilfield clusters could be prioritized to arrive at long term production projection. The remaining clusters could serve as plateau maintenance purpose afterwards.
Five oilfield clusters had been defined under the guidance of clusterization strategy. Three oilfield clusters had been recommended for Phase I production after optimization on the inter-cluster and intra-cluster level. 60 KBOPD of productivity with longer plateau is expected from clusterization development with convincing economical parameters, which fully satisfy the requirement of long distance pipeline.
This paper had proposed an innovative clusterization approach to define development strategy for small and scattered oilfields in a landlocked basin. The two-tier optimization process inherent in the clusterization approach could be of strong reference value to similar marginal blocks and basins.
Liu, He (RIPED, CNPC) | Huang, Shouzhi (RIPED, CNPC) | Sun, Qiang (RIPED, CNPC) | Ming, Eryang (RIPED, CNPC) | Li, Tao (RIPED, CNPC) | Han, Weiye (RIPED, CNPC) | Chen, Qiang (RIPED, CNPC) | Li, Yiliang (RIPED, CNPC) | Pei, Xiaohan (RIPED, CNPC) | Zhang, Shaolin (RIPED, CNPC)
Numbers of oil fields in China had entered high water cut stage. The inefficiency circulation happened frequently during water flooding of these oil fields because of seriously intraformational heterogeneity in thick reservoir. Based on oilfield development dynamic data, it indicated that the problems of inefficiency fluid injection and futility circulation could not be solved in vertical well exploitation, no matter using water flood or chemical flood. There was a certain thickness of unexploited or low flushing efficiency oil remained on the top of thick reservoir. The traditional lateral drilling techniques could not be applied in short radius within 5 1/2 inches to 7 inches casing which were regular casing sizes of injection well in these oil fields. To exploit remained oil, the recent method to increase flow conductivity was hydraulic jet technology. But it had several disadvantages, like small aperture diameter, short drilling distance, inaccuracy orientation and limited flow conductivity.
This paper introduces an ultrashort radius lateral drilling technique (URLD) which provides an efficient method to increase production by drilling into the target reservoir to build a flow channel between unexploited reservoir and wellbore. The ultrashort radius lateral drilling technique includes flexible lateral drilling tool, deflecting tool, directional tool, etc. The flexible lateral drilling tool, which is the key in URLD technique, is consisted of several flexible nipples in the length of 15 cm. It is connected by double offset universal joint between adjacent flexible nipples. The movable angle between adjacent flexible nipples is 4-6 degree. And a PDC drill bit is connected in front end of tool. The URLD technique can realize lateral drilling within 5 1/2 inches to 7 inches casing. It can be applied to target reservoir thicker than 2 m. The drilling track is controllable. Target error is within ±1 %. Minimum deflecting radius is 1.8 m. The drilling hole diameter is 114 mm. The length of lateral drilling is more than 100m in 5 1/2 inches casing and 200 m in 7 inches casing.
The URLD technique has applied in more than 20 wells in China, and barels oil per day increases by 3 to 5 times in average. The URLD technique provides a solution to exploit remained oil after long term water flooding, and increases the production of mature oil field in economical way.
In fractured reservoirs, seismic wave velocity and amplitude depend on frequency and incidence angle. The frequency dependency is believed to be principally caused by the wave-induced flow of pore fluid at the mesoscopic scale. In recent years, two particular phenomena, partial saturation and soft fractures, have been identified as significant mechanisms of wave induced flow. However these phenomena are usually treated separately. Recently a unified model was proposed for a porous rock with a set of aligned fractures filled with arbitrary fluid. Existing models treat waves propagating perpendicular to the fractures. In this paper, we extend the model to all propagation angles by assuming that the flow direction is perpendicular to the layering plane and is independent of the loading direction. We first consider the limiting cases through poroelastic Backus averaging, and then we obtain the full stiffness tensor of the equivalent TI medium. The numerical results show that when the bulk modulus of the fracture-filling fluid is relatively large, the dispersion and attenuation of P-waves are mainly caused by soft fracturs. While the bulk modulus of fluid in fractures is much smaller than that of matrix pores, the attenuation due to the ‘partial saturation’ mechanism dominants.
Presentation Date: Wednesday, October 19, 2016
Start Time: 9:15:00 AM
Location: Lobby D/C
Presentation Type: POSTER
Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The total number of drilled was 19, including 5 updip wells penetrated oil and gas zones, the remaining 14 downdip wells completed at principal oil zones. A unique co-development project of oil and gas had been performed since the start-up of field in July, 2010, including three phases:
Phase I: Prior to start-up of the field, In-situ gas injection was initiated. Single tubing string completion was utilized in updip wells, packer isolated oil and gas zones so that high-pressure gas could produce from the tubing and oil could produce from the annulus. After commencement, gas from updip wells was injected into downdip wells to maintain reservoir pressure and minimize water influx. The remaining gas was used to gas-lift at updip wells.
Phase II: Following pressure depletion of oil and condensate gas zones, gas-lift wells became inefficient. The packerless tubing string was extended to the bottom of perforations for commingling production of oil and gas condensate zones at updip wells. Well stream was produced from the casing annulus while recycling gas was injectied from compressors into the tubing for gas lift. Nitrogen injection was conducted at downdip wells.
Phase III: After water breakthrough, infill wells between updip and downdip wells were drilled for nitrogen injection to mitigate the water cut rising trend.
Actual production performance of oil and gas co-development is better than sequential production of oil and gas. Initial well production at two producers reached over 10,000 BOPD, Current recovery factor for oil is 25% and gas is 36%. Oil is producing at the level of 18,000 BOPD with average offtake rate of 5.8%. Simulation confirmed that ultimate recovery factor for oil could be over 50%.