A reservoir with bottom water drive mechanism has a high tendency to generate water coning effect in their production life. As a result of water coning phenomenon, the well has a low critical safe rate which limits the productivity of the reservoir. Consequently, a new innovation for completion design in an oil well with a bottom aquifer drive is needed. The author offers a Downhole Water Sink (DWS) system to solve this problem.
DWS is a dual completion design innovation where two tubing strings are installed into the well to produce both water and oil simultaneously by different tubing. The main principle of DWS is to create a stable pressure drawdown in oil and water zone so that a stable oil-water contact is formed. DWS application in a multilayered reservoir expected to be able to resolve the water coning phenomenon thus the recovery factor increased and the well becomes economic to be produced. In this paper, the study approach involved by numerical simulation within IMPES methodology (Implicit Pressure Explicit Saturation) and Thomas’s algorithm to solve iteration. Completion modeling is creating two wells on the similar coordinate in several layered reservoirs aims to produce oil and water separately on tubing on the well.
The percentage of water cut on oil production tubing is 0% while the percentage of water cut on water production tubing is 100%. This thing shows that DWS completion system will give a greater cumulative oil production in a high production rate and the oil is oil-free water. It is observed that the successful implementation of DWS in a multilayered reservoir is taken place. The well with DWS design configuration for the WDP system shows a better performance of oil productivity compares to a conventional well completion design. This result is supported by no water production observed at oil production tubing on the surface well level. There are some parameters that affect DWS system application modeling i.e. mobility ratio, vertical and absolute horizontal permeability (kv & kh) also perforation interval.
Down-Hole Water Sink is an appropriate innovation to eliminate water coning and producing oil with high recovery factor. DWS application in a multilayered reservoir with bottom aquifer driving mechanism shows a better performance of oil productivity compares to a conventional well completion design. This result is supported by no water production observed at oil production tubing on the surface well level.
The effectiveness of secondary and tertiary recovery projects depends heavily on the operator's understanding of the fluid flow characteristics within the reservoir. 3D geo-cellular models and finite element/difference-based simulators may be used to investigate reservoir dynamics, but the approach generally entails a computationally expensive and time-consuming workflow. This paper presents a workflow that integrates rapid analytical method and data-analytics technique to quickly analyze fluid flow and reservoir characteristics for producing near "real-time" results. This fast-track workflow guides reservoir operations including injection fluid allocation, well performance monitoring, surveillance, and optimization, and delivers solutions to the operator using a website application on a cloud-based environment. This web-based system employs a continuity governing equation (Capacitance Resistance Modelling, CRM) to analyze inter-well communication using only injection and production data. The analytic initially matches production history to determine a potential time response between injectors and producers, and simultaneously calculates the connectivity between each pair of wells. Based on the inter-well relationships described by the connectivity network, the workflow facilitates what-if scenarios. This workflow is suitable to study the impact of different injection plans, constraints, and events on production estimation, performance monitoring, anomaly alerts, flood breakthrough, injection fluid supply, and equipment constraints. The system also allows automatic injection re-design based on different number of injection wells to guide injection allocation and drainage volume management for flood optimization solutions. A field located in the Midland basin was analyzed to optimize flood recovery efficiency and apply surveillance assistance. The unit consists of 11 injectors and 22 producers. After optimization, a solution delivering a 30% incremental oil production over an 18-month period was derived. The analysis also predicted several instances of early water breakthrough and high water cut, and subsequent mitigation options. This system couples established waterflood analytics, CRM and modern data-analytics, with a web-based deliverable to provide operators with near "real-time" surveillance and operational optimizations.
Wei, Bing (Southwest Petroleum University) | Wang, Yuanyuan (Southwest Petroleum University) | Chen, Shengen (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Ning, Jian (Southwest Petroleum University) | Wang, Wanlu (Southwest Petroleum University)
Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
Zhang, Guohao (Tianjin Branch of CNOOC Ltd) | Liu, Zongbin (Tianjin Branch of CNOOC Ltd) | Li, Yanlai (Tianjin Branch of CNOOC Ltd) | Jia, Xiaofei (Tianjin Branch of CNOOC Ltd) | Sun, Zhaobo (Tianjin Branch of CNOOC Ltd) | Lv, Zuobin (Tianjin Branch of CNOOC Ltd)
In strong edge/bottom-water reservoir, unstable pressure drop and recovery degree in different horizontal well segments often lead to breakthrough of edge and bottom water, causing rapid water cut increase and productivity decrease, even burst water flood. Bohai LD oilfield was low-rising and strong edge/bottomwater reservoir with horizontal well pattern. Considering the status of LD Oilfield which was short of reliable water-controlling techniques during high water-cut stage, an applicative, effective and economical water control technology was urgently required. In the present work, water breakthrough characteristic template of horizontal well had been established through studying water breakthrough features of horizontal well locating at high permeability zone based on the mechanistic model. At the same time, combined with numerical simulation study on actual reserviors and physical parameters in the horizontal interval, the water breakthrough position of horizontal well had been further confirmed. On the basis of above, the water shutoff technology with concentric tube had been studied. It was through inserting a piece of concentric tube with small diameter into horizontal segment of horizontal well and optimizing design parameters of concentric tube in accordance with horizontal section flow profile. Through the water shutoff technology with concentric tube, all fluid production profiles of experimental well had been effectively improved in horizontal section, which attained the destination of oil production increment and water cut reduction.
Critical drawdown pressure for sand onset and its accuracy with change in water cut is a continuous area of study. The numerous parameters like grain cementation, viscosity of fluids, actual physics of sand production with fluids leads to a lot of uncertainty. In practical terms, it has been observed that these mechanisms lead to reduction in Uniaxial Compressive Strength of rocks. The objective of this paper is to present a novel method that not only helps on understanding the effect of water production on sand failure but to further predict the volumetric expected sand production up until a certain tolerable error.
A sand prone field within Malaysian region was identified and core tests were done to evaluate UCS and other rock strength parameters at different saturation of water to simulate the effect of water on rock strength. CDP evaluations were done and the values were calibrated with actual field data to have an accurate understanding of CDP values at different water cuts. Lastly, with the findings from field production data, limit was pushed further to develop a novel method to predict the volumetric sand production.
The proposed novel method has helped not only in understanding the effect of water production on sand failure but also on the amount of sand to be produced under different drawdown pressures with a reasonable accuracy. These results proved very useful in implementing Company's Holistic Sand Management strategy. The integration of this method with water cut predictions from reservoir simulation models helped the team to quantify the continue increasing sand production due to water cut increase. Company is replicating similar workflow in other sand prone fields for an effective sand management.
The approach is very novel as the theoretical modelling work has been effectively calibrated using real field data. This method has provided a high degree of confidence in estimating the amount of sand to be produced under different production conditions.
Authors consider this as a breakthrough in field of holistic sand management and very useful workflow for all other operators to emulate.
Li, Feng (Southwest Petroleum University) | Xie, Xiong (CNOOC-Shenzhen) | Huang, Li (CNOOC-Shenzhen) | Zhou, Luyao (CNOOC-Shenzhen) | Chang, Botao (Schlumberger) | Wang, Chao (Schlumberger) | Wang, Fei (Schlumberger) | He, Chengwen (Schlumberger)
In China, the main sandstone reservoir M of the LF oilfield entered the mature development stage with high water cut (average 93%) and 66.1% recovery. Remaining oil exists vertically in the H layer at the top section of this massive bottomwater reservoir and laterally at margins of current development area with less well control. The H layer consists of several thin (0.5 to 2 m) sand sublayers interbedded with calcareous tight sublayers with low permeability; the effective oil drainage radius of single borehole is 100 to 150 m. Maximum reservoir contact (MRC) technology was employed to increase drainage area and volumetric sweep efficiency for optimal production and recovery to rejuvenate this mature reservoir.
In an original hole with 98 to 99.9% water cut targeted for a workover operation, two new laterals were sidetracked to comprise a three-lateral MRC configuration with openhole completion to develop the SL1 target sublayer of the H layer. The success of MRC wells depends on an efficient openhole sidetrack and azimuth turning. Moreover, multilaterals need to precisely chase the sweet zone in the reservoir. Drilling into overlying shale causes borehole collapse, and penetrating the underlying tight zone causes fast bottom water breakthrough. Low resistivity contrast increases the difficulty of distinguishing the target zone from the shoulders. Sparse well control and limited seismic resolution bring high structural and stratigraphic uncertainties. Accordingly, effective services were equipped to overcome these challenges to achieve the required engineering and reservoir objectives. The new-generation hybrid rotary steerable system (RSS) tool provides stable, rapid, and accurate steering control, even with high dogleg severity, to achieve engineering objectives. With a balance between resolution and depth of investigation (DOI), high-definition deep-looking resistivity inversion uses the Metropolis coupled Markov chain Monte Carlo method to clearly identify multiple layers (more than three) within an approximately 6 m DOI, formation resistivity distribution, anisotropy, and dip, even in this low-resistivity-contrast environment. Reservoir details could be clearly unveiled to help MRC lateral steering along the thin target. Furthermore, a wide-range-displacement electrical submersible pump (ESP) helps optimize openhole performance.
Six new laterals were drilled in three MRC wells. Hybrid RSS tools provided 100% openhole sidetrack success rate, and laterals were turned laterally with 15 to 70° azimuth change and 200- to 570-m displacement to maximize the drainage area. Deep-looking inversion revealed high-definition reservoir details by delineating three key boundaries and four adjacent layers' profiles simultaneously and identifying target zone's thickness and property variation. The target sand is 0.5 to 2 m thick with resistivity of 2 to 9 ohm-m, surrounded by interbeds with resistivity 8 to 10 ohm-m. Within the refined 3D reservoir model, the horizontal laterals efficiently chased the top section of effective target sand while avoiding high-risk shoulders. Total 4298-m horizontal footage was achieved in six laterals with net-to-gross 91% in the SL1 thin, low-permeability reservoir. With the proper ESP configuration, approximately 688,500 bbl of oil have been produced as of December 2018. Especially in two workover MRC wells, after approximately 2.5 years of production, the current water cut is 96 to 97%, lower than water cut (98 to 99.9%) before the workover operation, and daily oil production increased significantly.
Integrated drilling, logging, and production services provided MRC efficiency to rejuvenate this thin, low-permeability and low-resistivity mature reservoir.
D-X oilfield implemented an infill adjustment from 2013 to 2015, adding 101 development wells, two central processing platforms and two wellhead platforms. After the adjustment, the oil field greatly improved the engineering processing capacity, but it had also entered a period of rapid decline. In order to mitigate the decline and improve the recovery rate, 65 adjustment wells were implemented in this oilfield after the first adjustment. Based on the new drilling data and production data, earlier inefficient well management was turned a more efficient well management, where the engineering processing space is fully utilized, the decline of oil field is alleviated, and the development effect is greatly improved.
Polymer gel treatment is a successful technology for conformance improvement. Achieving effective deep conformance control in high-temperature reservoirs requires improving the performance of gel in these environments and a deep understanding of gel-conformance control mechanisms inside reservoir rocks.
In this work, a laboratory study was conducted to evaluate a polyacrylamide/chromium gel system for a carbonate reservoir at high-temperature and high-salinity (HTHS) conditions. Displacement experiments combined with nuclear magnetic resonance (NMR) measurements were performed to investigate the mechanisms of conformance treatment as well as demonstrate the potential of oil production improvement by a gelling system. Coreflooding tests were performed on carbonate core samples with different configurations of high-permeability channels. Both gel treatment and polymer flooding experiments were conducted to quantify and differentiate between fluid-diversion and viscous effects on oil production improvement due to the treatment. Detailed spatial fluid variations inside the core samples before and after gel treatment were closely monitored using low-field NMR techniques.
Both coreflooding experiments and NMR measurements clearly showed that significant oil production improvement was achieved by gel treatment. The bypassed oil during waterflooding was effectively mobilized. Gel treatment is more efficient in oil production improvement for more heterogeneous core samples. The comparison study of gel treatment and polymer flooding helps gain insight into the mechanisms of oil displacement.
Results show that the blockage or fluid-diversion effect plays a more significant role in oil production improvement after gel treatment. The viscous effect of gelant flow helps mobilize oil in the matrix region. The oil production improvement by gel treatment is mainly attributed to the fluid-diversion effect, especially for the treatment in high-permeable configuration. Moreover, results of the study demonstrate the potential of the studied gel system for carbonate reservoirs at high temperature. NMR techniques add additional valuable information to conventional displacement tests to identify the dominant mechanisms of oil mobilization.
The case study describes a modeling and simulation study of an inverted ESP completion to address three fundamental objectives. A) Increasing the ultimate oil recovery in the massive sands of Cretaceous age in Greater Burgan field by managing water production B) Mitigating the rapid water coning conditions in this high permeable water drive reservoir and C) Designing an optimal operating strategy with Downhole Water Sink (DWS) to control water production and manage well performance. A 2×2km sector was carved out from the full field geological model with 12 wells including the study well. The study well was producing at high water cut at the time of the study. All static properties were updated, and the model was history matched for production, pressure and saturation. Several sensitivity runs were performed, and prediction scenarios were run for 5 years to observe well production behavior in time. The well model was setup with an inverted ESP between straddle packers to produce water from below OWC and inject into bottom reservoir with a production string above to produce from the oil zone. This setting ensured a reverse oil cone being generated from below OWC in the reservoir under production. The aquifer model was finite in size enabling bottom water influx. Simulation results showed that implementation of DWS technology made the water production reduced by 18% during five years with an increase in oil production of nearly 25% in the study well. To maintain continuous well offtake rate, a range of water rates to be produced and injected to bottom reservoir have been studied. Several iterative runs were made to investigate the best completion interval and injection & production rates. The profiles of oil water interface near well bore indicated good reduction in the cone height as compared to normal completion. The results also showed significant improvement in oil recovery within the drainage radius of the well from the simulations. Simulation results provided good understanding of the saturation change near well bore area under different production rates. Prediction runs were made for sustainable oil production under natural flowing condition and the conditions to switch over to production under artificial lift. Production of thin layers of remaining oil from within high permeable massive Burgan middle sands has been a high concern due to very high water cuts because of coning. The study results have provided encouraging option with DWS technique to improve recovery from the reservoir.
The surface choke has been utilized in the oil industry to control withdrawal rates per well and to optimize production especially after water breakthrough. However, as found out from this study, applying undue restrictions in horizontal wellbores intersecting high permeability features can have an adverse impact on well performance and unnecessarily lock oil potential.
This paper investigates the effect of surface choke on water cut and flow contribution along horizontal wellbores that encountered natural fractures and high permeability streaks (Super-Ks). The study considered different down-hole completions; open-hole and cased-hole. The investigation was carried out using Multi Phase Flow Meter (MPFM) measurements at different choke sizes in addition to production logs (FSI), wellbore simulation modeling, and real-time data. Instant data monitoring was instrumental in insuring stabilization of sub-surface static pressure while performing many rate tests at different choke sizes. Moreover, it flagged the role of rate stabilization on water cut behavior and rate data quality.
The presence of conductive fractures and Super-Ks substantially influences the flow profile and water cut of horizontal wellbores. These features create high permeability conduits along wellbores such that they dominate production and may cause some matrix sections to contribute little or nothing as observed on FSI profiles. The effect of fractures on production from less permeable sections in the wellbore was investigated at different operating rates using horizontal wellbore simulation modeling.
Both MPFM measurements and FSI logs showed that water cut from horizontal wells, affected by fractures and/or Super-Ks, can decrease if they're flowed at higher rates. Upon reviewing and analyzing data from numerous FSI logs, the study has been able to relate the water cut and surface choking to the well productivity index (PI). Consistently, wells with PI more than twice the averaged matrix PI were found to always perform better at bigger choke sizes. By choke relaxation, the water cut decreased by up to 22% while increasing oil production. Wellbore modeling also suggested that the influence of a fracture on flow contribution from remaining sections in the wellbore can be minimized if the well is operated at higher rates. Restrictive surface chokes were found to disproportionately affect lower permeability sections compared to conductive fractures or Super-Ks which in most cases were invaded by water after water breakthrough. Relaxing these surface chokes allowed more contribution of dry oil from the lower permeability sections, hence the increase in overall oil production and drop in water cut in the affected wells.