Enhancing Oil Recovery With Bottom Water Drainage Completion

2014 ◽  
Vol 136 (4) ◽  
Author(s):  
Ephim Shirman ◽  
Andrew K. Wojtanowicz ◽  
Hilal Kurban
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Oil Production ◽  
Fold Increase ◽  
Recovery Process ◽  
Field Trials ◽  
Experimental Results ◽  
Water Drainage ◽  
Performance Study ◽  
Time Required

Field trials and physical modeling of wells with downhole water sink (DWS) completions have demonstrated controlled water coning and increased oil production rate. However, no field trials were long enough to show DWS potential in improving of oil recovery in comparison with conventional wells. Presented here are theoretical and experimental results from a DWS recovery performance study. The recovery study involved experiments with a physical model and computer simulations. The experimental results reveal that DWS dramatically accelerates the recovery process; a fivefold increase of the oil production rate was reached by adjusting the water drainage rate at the bottom completion. The results also show a 70% increase of oil recovery; from 0.52 to 0.88 for conventional and DWS completions, respectively. The computer-simulated experiments with commercial reservoir simulator demonstrate progressive improvement of recovery with downhole water drainage from 0.61 to 0.79 with no drainage and maximum drainage, respectively—a 24% increase of recovery factor, and a fivefold reduction of the time required to reach the limiting value of water cut, 0.98. However, the accelerated recovery process with DWS requires a substantial, up to 3.5-fold, increase of total water production. The simulation experiments also show that the main advantage of using DWS is its flexibility in controlling the recovery process. For conventional completions, recovery could be slightly increased by reducing production rates and largely increasing production times. For DWS, a combination of the top and bottom rates could be optimized for maximum recovery and minimum production time.

scholarly journals An Improved Mathematical Model for Accurate Prediction of the Heavy Oil Production Rate during the SAGD Process

Processes ◽  
2020 ◽  
Vol 8 (2) ◽  
pp. 235
Author(s):  
Aria Rahimbakhsh ◽  
Morteza Sabeti ◽  
Farshid Torabi
Keyword(s):  
Production Rate ◽  
Penetration Depth ◽  
Oil Recovery ◽  
Current Model ◽  
Oil Production ◽  
Exponential Model ◽  
Analytical Models ◽  
Test Facility ◽  
Drainage Rate ◽  
Heat Penetration

Steam-assisted gravity drainage (SAGD) is one of the most successful thermal enhanced oil recovery (EOR) methods for cold viscose oils. Several analytical and semi-analytical models have been theorized, yet the process needs more studies to be conducted to improve quick production rate predictions. Following the exponential geometry theory developed for finding the oil production rate, an upgraded predictive model is presented in this study. Unlike the exponential model, the current model divides the steam-oil interface into several segments, and then the heat and mass balances are applied to each of the segments. By manipulating the basic equations, the required formulas for estimating the oil drainage rate, location of interface, heat penetration depth of steam ahead of the interface, and the steam required for the operation are obtained theoretically. The output of the proposed theory, afterwards, is validated with experimental data, and then finalized with data from the real SAGD process in phase B of the underground test facility (UTF) project. According to the results, the model with a suitable heat penetration depth correlation can produce fairly accurate outputs, so the idea of using this model in field operations is convincing.

Extractive Capacity of CO2 in Oil Saturated Porous Media

2012 ◽  
Vol 524-527 ◽  
pp. 1807-1810
Author(s):  
Hao Chen ◽  
Sheng Lai Yang ◽  
Fang Fang Li ◽  
San Bo Lv ◽  
Zhi Lin Wang
Keyword(s):  
Porous Media ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Oil Production ◽  
Supercritical Condition ◽  
Experimental Results ◽  
Water Flooding ◽  
Saturated Porous Media ◽  
Reservoir Conditions

CO2 flooding process has been a proven valuable tertiary enhanced oil recovery (EOR) technique. In this paper, experiment on extractive capacity of CO2 in oil saturated porous media was conducted under reservoir conditions. The main objectives of the study are to evaluate extractive capacity of CO2 in oil saturated natural cores and improve understanding of the CO2 flooding mechanisms, especially in porous media conditions. Experimental results indicated that oil production decreases while GOR increases with extractive time increases. the changes of the color and state of the production oil shows that oil component changes from light to heavy as extractive time increases. In addition, no oil was produced by water flooding after extractive experiment. Based on the experimental results and phenomena, the main conclusion drawn from this study is that under supercritical condition, CO2 has very powerful extractive capacity. And the application of CO2 flooding is recommended for enhancing oil recovery.

scholarly journals NANO-SURFACTANT HUFF AND PUFF OPTIMATIZATION IN MARGINAL X FIELD USING COMMERCIAL SIMULATOR

2019 ◽  
Vol 42 (2) ◽  
pp. 51-57
Author(s):  
Ariel Paramastya ◽  
Steven Chandra ◽  
Wijoyo Niti Daton ◽  
Sudjati Rachmat
Keyword(s):  
Interfacial Tension ◽  
Production Rate ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Oil Production ◽  
Full Scale ◽  
Economic Aspect ◽  
Economic Optimization ◽  
Single Well

Economic optimization of an oil and gas project is an obligation that has to be done to increase overall profi t, whether the fi eld is still economically feas ible or the fi eld has surpassed its economic limit. In this case, a marginal fi eld waschosen for the study. In this marginal fi eld EOR methods have been used to boost the production rate. However, a full scale EOR method might not be profi table due to the amount of resources that is required to do it. Alternatively, Huff and Puff method is an EOR technique that is reasonable in the scope of single well. The Huff and Puff method is an EOR method where a single well serves as both a producer and an injector. The technique of Huff and Puff: (1) The well isinjected with designed injection fl uid, (2) the well is shut to let the fl uid to soak in the reservoir for some time, and (3) the well is opened and reservoir fl uids are allowed to be produced. The injection fl uid (in this case, nano surfactant) is hypothesized to reduce interfacial tension between the oil and rock, thus improving the oil recovery. In this study, the application of Huff and Puff method using Nanoparticles (NPs) as the injected fl uid, as a method of improving oil recovery is presented in a case study of a fi eld in South Sumatra. The study resulted that said method yields an optimum Incremental Oil Production (IOP) in which the economic aspect gain more profi t, and therefore it is considered feasible to be applied in the fi eld.

Experimental Investigation of CO2 Huff and Puff Process Based on Three-Dimensional Physical Models

2021 ◽  
Author(s):  
Xiang Tang ◽  
Yiqiang Li ◽  
Zhihao Yu ◽  
Miaomiao Xu ◽  
Rui Zhou
Keyword(s):  
Prediction Model ◽  
Oil Recovery ◽  
Three Dimensional ◽  
Oil Production ◽  
Experimental Results ◽  
Physical Models ◽  
Tight Reservoir ◽  
Resonance Test ◽  
Experimental Apparatus ◽  
Production Prediction

Abstract As an important enhanced oil recovery method for tight reservoirs, CO2 huff and puff (HnP) is getting more attention in recent years. It is urgent to systematically study the characters of CO2 HnP. Due to the limitations of numerical simulation, it is more reliable and reasonable to study the development characteristics of CO2 HnP through experiments. The objective of this work is to conduct comprehensive experiments to clarify the characters and main mechanisms of CO2 HnP process based on the three-dimensional (3D) physical models. A 3D physical experimental apparatus with circumstance of high temperature and high pressure has been developed, which is mainly used to support the models with a fixed confining pressure and temperature. Based on the similarity criterion of dimensionless conductivity, two different 3D physical models (30cm×30cm×3.5cm) with a horizontal well and fractures are made from outcrops to imitate the different reservoirs. Under these preconditions, some CO2 HnP experiments were conducted to investigate the development characteristics from the 3D physical models.Also,long core experiments were carried out to establish and verify the production prediction model, combined with expansion test, diffusion test and nuclear magnetic resonance test. The experimental results show that the development process of CO2 HnP can be divided into four stages: CO2 backflow, Gas production with attached oil, High-speed oil production and Decay. The main mechanism of oil production in each stage is different. With the increase of the cycle number, the recovery factors of both models first increase and then decrease, while the oil/gas replacement rates may drop rapidly. The fractures have been proven to increase the oil recovery from 21.2% to 36.7% after ten rounds of CO2 HnP. Based on the analysis of expansion and molecular diffusion, a production prediction model was established, and the average error between the predicted results and the experimental results is 7.7%, which has good applicability and accuracy. In this paper, some large-scale 3D physical model experiments with CO2 HnP for tight reservoir were elaborated. The development characteristics of CO2 HnP were analyzed, and a production prediction model was established. A lot of valuable experimental data and a better understanding on CO2 HnP process in tight reservoir have been obtained.

Optimal Application Conditions for Steam/Solvent Coinjection

2015 ◽  
Vol 18 (01) ◽  
pp. 20-38 ◽  
Author(s):  
Mohsen Keshavarz ◽  
Ryosuke Okuno ◽  
Tayfun Babadagli
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Oil Production ◽  
Detailed Knowledge ◽  
Critical Question ◽  
Factors Affecting ◽  
Operation Conditions ◽  
Solvent Retention ◽  
Edge Temperature

Summary Laboratory and field data, although limited in number, have shown that steam/solvent coinjection can lead to a higher oil-production rate, higher ultimate oil recovery, and lower steam/oil ratio, compared with steam-only injection in steam-assisted gravity drainage (SAGD). However, a critical question still remains unanswered: Under what circumstances can the previously mentioned benefits be obtained when steam and solvent are coinjected? To answer this question requires a detailed knowledge of the mechanisms involved in coinjection and an application of this knowledge to numerical simulation. Our earlier studies demonstrated that the determining factors for improved oil-production rates are relative positions with respect to the temperature and solvent fronts, the steam and solvent contents of the chamber at its interface with reservoir bitumen, and solvent-diluting effects on the mobilized bitumen just ahead of the chamber edge. Then, the key mechanisms for improved oil displacement are solvent propagation, solvent accumulation at the chamber edge, and phase transition. This paper deals with this unanswered question by providing some key guidelines for selecting an optimum solvent and its concentration in coinjection of a single-component solvent with steam. The optimization considers the oil-production rate, ultimate oil recovery, and solvent retention in situ. Multiphase behavior of water/hydrocarbon mixtures in the chamber is explained in detail analytically and numerically. The proposed guidelines are applied to simulation of the Senlac solvent-aided-process pilot and the Long Lake expanding-solvent SAGD pilot. Results show that an optimum volatility of solvent can be typically observed in terms of the oil-production rate for given operation conditions. This optimum volatility occurs as a result of the balance between two factors affecting the oil mobility along the chamber edge: reduction of the chamber-edge temperature and superior dilution of oil in coinjection of more-volatile solvent with steam. It is possible to maximize oil recovery and minimize solvent retention in situ by controlling the concentration of a given coinjection solvent. Beginning coinjection immediately after achieving interwell communication enables the enhancement of oil recovery early in the process. Subsequently, the solvent concentration should be gradually decreased until it becomes zero for the final period of the coinjection. Simulation case studies show the validity of the oil-recovery mechanisms described. In the final section of the paper, a limited economic analysis of SAGD and different coinjection cases is provided.

scholarly journals  Brine-Dependent Recovery Processes (Smart-Water/Low-Salinity-Water) in Carbonate and Sandstone Petroleum Reservoirs: Review of Laboratory-Field Studies, Interfacial Mechanisms and Modeling Attempts

2018 ◽  
Author(s):  
Adedapo N. Awolayo ◽  
Hemanta K. Sarma ◽  
Long X. Nghiem
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Ionic Composition ◽  
Recovery Process ◽  
Field Studies ◽  
Field Trials ◽  
Research Area ◽  
Wettability Alteration ◽  
Smart Water ◽  
Underlying Mechanisms

Brine-dependent recovery process has seen much global research efforts in the past two decades because of their benefits over other oil recovery methods. The process involves the tweaking of the ionic composition and strength of the injected water to improve oil production. In recent years, several studies ranging from laboratory coreflood experiments by many researchers to field trials by several companies admit to the potential of recovering additional oil in sandstone and carbonate reservoirs. Sandstone and carbonate rocks are composed of completely different minerals, with varying degree of complexity and heterogeneity, but wettability alteration has been widely considered as the consequence rather than the cause of brine-dependent recovery. However, there is no consensus on the cause as several mechanisms have been proposed to relate the wettability changes to the improved recovery. This review paper aims to provide a state-of-the-art development in published research and various efforts of the industry. This review outlines an overview of laboratory and field observations, descriptions of underlying mechanisms and their validity, the complexity of the oil-brine-rock interactions, modelling works, and comparison between sandstone and carbonate rocks. The provided information is intended to provide the reader with up-to-date information, point to relevant studies for those who are new and those implementing either laboratory- or field-scale projects to speed up the process of further investigations in this research area. Overall, the outcome of this review would potentially be of immense benefit to the oil industry.

Green Well Stimulation Fluids for Enhanced Oil Recovery from Tight Sand Formations: Field Wide 70+ Wells Study Over 4 Years

2021 ◽  
Author(s):  
Martin Shumway ◽  
Ryan McGonagle ◽  
Anthony Nerris ◽  
Janaina I.S. Aguiar ◽  
Amir Mahmoudkhani ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Cost Effective ◽  
Field Trials ◽  
Lessons Learned ◽  
Formation Damage ◽  
Well Stimulation ◽  
Tight Formations ◽  
History Of ◽  
Organic Deposits

Abstract Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.

Efficiency Analysis of the Geological-Technical Activities in Severo-Ostrovnoe Field

2019 ◽  
Vol 16 (11) ◽  
pp. 4584-4588
Author(s):  
I. A. Pogrebnaya ◽  
S. V. Mikhailova
Keyword(s):  
Hydraulic Fracturing ◽  
Production Rate ◽  
Oil Recovery ◽  
Oil Production ◽  
Horizontal Wells ◽  
Oil Field ◽  
Field Development ◽  
Multi Stage ◽  
Field Works ◽  
Technical Measures

The work is devoted to identifying the most relevant geological and technical measures carried out in Severo-Ostrovnoe field from the period of its development to the present. Every year dozens of geotechnical jobs (GJ) are carried out at each oil field-works carried out at wells to regulate the development of fields and maintain target levels of oil production. Today, there are two production facilities in the development of the Severo-Ostrovnoe field: UV1a1 and BV5. With the help of geotechnical jobs, oil-producing enterprises ensure the fulfillment of project indicators of field development (Mikhailov, N.N., 1992. Residual Oil Saturation of Reservoirs Under Development. Moscow, Nedra. p.270; Good, N.S., 1970. Study of the Physical Properties of Porous Media. Moscow, Nedra. p.208). In total, during the development of the Severo-Ostrovnoe field, 76 measures were taken to intensify oil production and enhance oil recovery. 12 horizontal wells were drilled (HW with multistage fracking (MSF)), 46 hydraulic fracturing operations were performed, 12 hydraulic fracturing operations were performed at the time of withdrawal from drilling (HW with MSF), five sidetracks were cut; eight physic-chemical BHT at production wells; five optimization of well operation modes. The paper analyzes the performed geological and technical measures at the facilities: UV1a1∦BV5 of the Severo-Ostrovnoe field. Four types of geological and technical measures were investigated: hydraulic fracturing, drilling of sidetracks with hydraulic fracturing, drilling of horizontal wells with multi-stage hydraulic fracturing, and physic-chemical optimization of the bottom-hole formation zone. It was revealed that two geotechnical jobs, namely, formation hydraulic fracturing (FHF) and drilling of lateral shafts in the Severo-Ostrovnoe field are the most highly effective methods for intensifying reservoir development and increasing oil recovery. SXL was conducted at 5 wells. The average oil production rate is 26.6 tons per day, which is the best indicator. Before this event, the production rate of the well was 2.1 tons per day. Currently, the effect of ongoing activities continues.

Sign in / Sign up

Export Citation Format

Share Document