Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Ramachandran, Hariharan (The University of Texas at Austin, Hildebrand Department of Petroleum and Geosystems Engineering) | Shen, Yang (PetroChina Research Institute of Petroleum Exploration&Development) | Yang, Heng (China National Oil and Gas Exploration and Development Corporation) | Shen, Zhijun (China National Oil and Gas Exploration and Development Corporation) | Nong, Gong (China National Oil and Gas Exploration and Development Corporation)
The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area has been put into production about 10 years, existing problems of productivity declining and produced gas-oil ratio rising. Therefore, the development optimization for the early producing area should be conducted in order to obtain the more profitable oil recovery. A typical foamy oil reservoir simulation model using 5 components was created to understand the remaining oil distribution features. Based on above understandings, technical strategies were proposed for infilling well deployment in the early producing area. Results show that the gravity drainage and gravity differentiation of oil and gas during the cold production of foamy extra-heavy oil from horizontal wells by foam flooding are the main mechanisms for formation of remaining oil. And the influence factors of remaining oil distribution include horizontal well spacing, reservoir thickness, reservoir heterogeneity, interlayer distribution and reservoir rhythm. Thus tor foamy extra-heavy oil CHOP process, the enriched remaining oil area is the place between two adjacent horizontal wells with well spacing of 600m. Therefore, well infilling is an effective measure improving oil recovery factor of cold production, and the well infilling should be implemented as soon as possible to obtain better performance of cold production.
Fu, Jin (CNPC Engineering Technology R&D Company Ltd.) | Wang, Xi (CNPC Engineering Technology R&D Company Ltd.) | Zhang, Shunyuan (CNPC Engineering Technology R&D Company Ltd.) | Chen, Chen (CNPC Engineering Technology R&D Company Ltd.)
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is an onshore heavy oil field in South America. The heavy oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. According to the reserve report released by PDVSA by the end of 2016, JUNIN Block that is situated in east of Orinoco Oilfield has an OOIP of 178*108bbl.
Data of drilled wells and distances between offset horizontal intervals in Orinoco were both studied to improve ultimate production rates. 3-dimension borehole trajectories were designed and the most effective anti-collision measures were taken.
After optimziation 8-12 horizontal wells are distributed on one pad. As the horizontal interval extends, the stable production time is prolonged and the accumulative production per well improves. However, the recovery rate stops increasing when the horizontal interval is over 1600m in JUNIN Block. Economically a large space between offset horizontal intervals results in fewer wells and lower costs, but a smaller space contributes to a higher production efficiency per well. If the space exceeds 600m, the accumulative production rate increases much more slightly. A three-dimension well trajectory consists of a vertical interval, an angle building interval, an angle holding interval, an angle building & direction changing interval, a direction turning interval as well as an absolute horizontal interval.
Since Petrobras developed the first ever offshore deep reservoir (Lula) by scale in 2006, Brazil has been conducting a progressive campaign targeting hydrocarbons buried under deep water, which contributes to discovery of Lula, Carioca, Jupiter, Buzios, Libra and other giant presalt reservoirs in Santos Basin after Campos Basin, where there are 9 oil fields ranking among the top 20 offshore oil fields in terms of OOIP. By June 2017 over 160×104bbl oil and gas were produced per day in deep water of Santos Basin, taking up 57.1% of the total yield of Campos and Satos.
Creep deformation of ultra-thick salt beds, severe loss of limestones, poor drillability of formations and insufficiency of deep water drilling equipment all make drilling and completion challenges more complicated. Mud systems and casing programs are optimized to conquer creep of salt and formation of hydrates due to low downhole temperature. Turbines + impregnated bits are deployed to improve drilling efficiency of siliceous carbonates (Lagoa Feia A Group). Precise control of ECD and efficient LCMs solved engineering challenges caused by narrow density windows (Lagoa Feia B Group and Lagoa Feia C Group).
This paper submits the monitoring methodology applied to horizontal wells associated to the First polymerized water injection pilot project, developed in Zuata Principal Field from Hugo Chavez Orinoco Oil Belt (Venezuela). Zuata Principal is a mature field, formed by unconsolidated sands of deltaic and fluvial sedimentary environments, saturated with extra heavy crude of API gravity between 8.5 to 9.5, and viscosities between 2000 to 5000 cp at reservoir conditions. The basic units of production construction (Clusters) are mostly made of horizontal wells perforated in a radial pattern, which operate under the artificial lifting method of progressive cavity pump (PCP). The pilot project was developed in a deltaic environment. As a part of the surveillance plan of the project, it was established one methodology for the control of the producer wells, using the following sources of information: - Measurements of pressure and temperature at bottom hole (real time), using multiple pressure and temperature sensors placed in the horizontal section and temperature distributed sensors, meaning fiberoptic sensors.
Summary A workflow to generate seismic well ties in PS converted wave seismic sections using sonic logs was created by estimating Vp/Vs relationships and the time difference between the arrival time of the P-P and the PS waves to several key events. The results were PS converted wave synthetic seismograms tied to well-defined seismic reflectors at different depths. These positive results made possible the creation of a step by step workflow to tie wells to converted wave seismic and generate synthetic seismograms. Introduction The seismic method of reflection P-P wave has been the most important exploration method in the oil and gas industry. Nevertheless, this method does not clarify all the uncertainties that can be encountered during subsurface exploration and development.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, December 09 Monday, December 10 Tuesday, December 11 Wednesday, December 12 Filter By Session Type All Sessions General Activities Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Energy4Me Training Course/Seminar Sunday, December 09 07:00 - 15:00 Field Trip: An Integrated Approach to Geologic Outcrops for Boosting Reservoir Understanding Jal Az Zor Escarpment, North of Kuwait City Ticketed Event Field Trip Jal Az Zor Integrated Field Course An Integrated Approach to Geologic Outcrops for boosting Reservoir Understanding When: 9 December 2018 Where: Jal Az Zor Escarpment, north of Kuwait City Organizers: KOC, with KOC and Shell SMEs The field trip will provide an integrated approach to geologic outcrops, using Jal Az Zor examples, that will trigger reflections in the participants about the implications of heterogeneities, scale, and 3D distribution of rock properties to models, studies, activities, and insights pertinent to reservoir analysis. The field course is specifically designed to relate the geology to a variety of subsurface disciplines involved in heavy oil development. Topics addressed will include baffles, reservoir modelling, steam conformance, cap rock integrity, well spacing, integration of well, reservoir, and facilities management (WRFM), and observation wells placement. The ultimate goals are to gain an appreciation for the value that the understanding of vital elements of rock description and sedimentology have for reservoir studies, and for the enhancement of production strategies. Group discussion will be encouraged to share knowledge and trigger new perspectives.
This study is based mainly on the Cubagua formation belonging to the Dragon field, where the intervals of interest of the deposits are poorly consolidated and the cementation of the grains of sand is poor, as to be able to withstand the efforts applied as a result of the passage of the produced fluids through them, being able to start the phenomenon of sandblasting. The realization of this work consisted of the use of the BP-Willson methodology
Although various novel techniques were developed in reservoir engineering for estimation of hydrocarbons initially in place (HCIIP), conventional material balance still remains as one of the most reliable. However, material balance requires availability of average reservoir pressure measurements, as these data is a critical input for its calculations. Alas, there are multiple scenarios where reservoir pressure cannot be measured as it requires for the well to be shut-in and this is subject to economic and operational restrictions.
In contrast, daily production data is commonly available and can be used to calculate the HCIIP by applying any production data analysis technique, such as the Dynamic Material Balance (DMB) method. It was widely demonstrated in recent years, how the application of such methods to volumetric gas reservoirs and naturally fractured reservoirs produced accurate and reliable estimations. Nevertheless, for the case of water drive gas reservoirs, were the water influx term should be introduced into the iterative process, research is scarce and field case applications are limited.
An extension to the DMB technique for water-drive gas reservoirs is presented in this paper. A methodology for simultaneous estimation of the Original Gas-in-place (OGIP) and the water influx term is derived and detailed. This is achieved by coupling the DMB technique with the Fetkovich aquifer model. Average reservoir pressure estimation can also be attained as a result of the coupled method.
This method was validated by means of numerical simulation on a synthetic model and a field study case. The OGIP, water influx volumes and average reservoir pressure calculated by the proposed coupled method were compared with simulator output where relative error was found to be negligible. Furthermore, application of the coupled method to the field study case yielded comparable results to those obtained by application of the volumetric method and conventional material balance.
The objective of the study was to estimate how much the mobility of a polymeric solution is affected at reservoir conditions, in an enhanced oil recovery process using polymer. This document describes the different techniques and methodologies to establish polymer solution degradation, and its effects over the expected behavior.
The analysis was performed using the results from 4 fall off tests at different stages of the injection process, the test were executed every three months after the beginning of the injection of the polymer solution, following the surveillance plan established. Other diagnostics techniques were also studied, in order to discard geologic features that could affect the injection process, among then: Hall plot diagnostics and temperature logging with fiber optics sensors.
The mobility of the polymer solution at reservoir conditions was determined. The affectation of the polymer solution is related to particular conditions of each section of the reservoir, meaning that minerals in the reservoir rock, and salinity of the connate water, could be the possible reasons why the polymer was affected, and exhibited a higher mobility compared to the design parameters. Later it was observed that the polymer mobility decreased over time, indicating that the polymer solution was no longer affected by in situ conditions.
To establish the performance of an enhanced recovery process using polymer, in the case of extra heavy oil reservoirs, it is necessary to evaluate the actual performance, and depend not only of the core test and simulation results. The analysis accomplished in this work was used to obtain important information necessary to asset feasibility, in the case of a larger scale implementation.
This paper submits the monitoring methodology applied to horizontal wells associated to the First polymerized water injection pilot project, developed in Zuata Principal Field from Hugo Chavez Orinoco Oil Belt (Venezuela). Zuata Principal is a mature field of unconsolidated sands of deltaic and fluvial sedimentary environments, saturated with extra heavy crude of API gravity between 8.5 to 9.5, and viscosities between 2000 to 5000 cp at reservoir conditions. The basic units of production construction (Clusters) are mostly made of horizontal wells perforated in a radial pattern, which operate under the artificial lifting method of progressive cavity pump (PCP). The pilot project was developed in a deltaic environment.
Jin, Fu (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Xi, Wang (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Shunyuan, Zhang (CNPC Drilling Research Institute)
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is the unique huge ultra-tight oilfield that has not been developed by scale in the world. The high-density tight oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. ML Block whose OOIP is 178*108bbl is situated in east of the oilfield, while cluster horizontal well drilling and cold production technologies are still under research there.
Based on precise geological researches numerical simulation was carried out to optimize cold production of ultra-tight oil with foamy oil flow patterns in horizontal wells, including optimization of well placement, well spacing and horizontal section length. The near-bit geo-steering drilling technology was applied on adjacent wells to test its performance, while an experiment was conducted with PVT apparatuses to examine the effect of pressure decline rates on foamy oil flow. A long core pressure depletion test was accomplished to reveal the effect of foamy oil flow on recovery factors.
Three-dimension cluster horizontal well drilling and completion technologies shall be applied to develop ultra-tight oil reservoirs in huge loose sandstones, with the near-bit geo-steering drilling technology that controls landing points and horizontal sections in real time, keeping the bit move ahead along the lower boundary of the reservoir. Therefore, recovery rates may be dramatically improved due to the gravity drainage of ultra-tight oil. The most appropriate spacing of horizontal wells (500-600m) and horizontal section length (800-1200m) were determined to achieve the maximum recovery rate. The experiment proves that the recovery rate improves as the formation permeability increases, which means the "worm hole" contributes to heavy oil extraction. Boreholes with relatively large diameters, extensive perforated holes and slotted liners may be used to complete wells. In order to take the most advantages of the foamy oil flow mechanism high displacement ESPs shall be used with the selected thinner squeezed at the bottom, otherwise PC pumps with the thinner added at the wellhead are recommended.
Cold production technologies applied in ML Block save the overall production cost by 15.2%, improving the ultimate recovery rate by 8.6%. The foamy oil flow theory is improved, while it is the first time to integrate foamy oil flow production technologies with cluster horizontal well drilling technologies and near-bit geo-steering drilling technologies. As a result, the overall production rate of tight oil was greatly improved and the average production life of wells was extended.