Experimental Study on Type and Accuracy Optimization of Sand Control in Sand-Producing Heavy Oil Well

2021 ◽  
Author(s):  
Jianhua Bai ◽  
Yugang Zhou ◽  
Huaxiao Wu ◽  
Shunchao Zhao ◽  
Baobing Shang ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Retention Rate ◽  
Weighted Average ◽  
Optimization Method ◽  
Oil Wells ◽  
Oil Well ◽  
Retention Performance ◽  
Filter Screen ◽  
Sand Control ◽  
Production Stages

Abstract This paper proposes a set of methods for selecting the type of sand control screen and optimizing the accuracy in heavy oil Wells, which take into account the requirements of sand control and productivity protection in heavy oil Wells. Sand retaining experiments are carried out with slotted screen, wire wrapped screen and metal filter screen under the condition of oil and water mixed sand carrying flow. In order to optimize the sand control screen suitable for heavy oil well, this paper uses the weighted average method to quantitatively evaluate the flow performance, sand retention performance and oil conductivity of the screen. Then, repeat the experiment by changing the accuracy of the screen to optimize the accuracy. The experimental results show that the permeability of the three kinds of sand control screens is about 2μm2 when only heavy oil plugging occurs. Under the combined plugging action of formation sand and heavy oil, the slotted screen has the highest permeability, and its conductivity to heavy oil is 10% higher than that of the other two screens. The silk-wound screen has the best sand retention performance, with a sand retention rate of more than 90%. Through the quantitative evaluation of the sand control performance of three kinds of screens in different production stages of heavy oil Wells, the slit screen is selected as the optimal screen. For simulated formation sand with a median particle size of 250μm, the optimal sand control accuracy is 200μm. This paper provides a quantitative optimization method of screen type and accuracy for sand control design of sand-producing heavy oil Wells, so as to maximize the productivity under the premise of ensuring sand-producing control of heavy oil Wells.

Study on Preparation of Water-Soluble DRA for High Water Heavy Oil Well and Field Application Evaluation

2012 ◽  
Vol 616-618 ◽  
pp. 680-684
Author(s):  
Zheng Jun Long ◽  
Ya Rong Fu ◽  
Dong Qing Li ◽  
Li Xia Fu ◽  
Qian Fu
Keyword(s):  
Drag Reduction ◽  
Heavy Oil ◽  
High Water ◽  
Oil Wells ◽  
Water Soluble ◽  
Viscosity Reduction ◽  
High Water Content ◽  
Oil Well ◽  
Production Plant ◽  
Oil Viscosity

The high water content of heavy oil emulsions are O / W or W / O unstable estate, to solve the problem of heavy oil wells in the viscosity, after a large number of laboratory tests, a water-soluble drag reduction agent(DRA) with excellent drag reducing effect for high water heavy oil well is developed. The water-soluble DRA does not have combustible nature and solves also the problem of the security risk commonly used lower flash point viscosity reducing agent in paraffin oil well. The formulations and preparation method of the water-soluble drag reduction agent are introduced and the field applications are evaluated in this paper. The applications of more than 110 oil wells in Fifth Oil Production Plant in North China Oilfield have shown that the heavy oil viscosity reduction and drag reduction effects of water-soluble DRA are remarkable, and the hot wash cycle of oil well is prolonged.

scholarly journals Downhole electric heating of heavy-oil wells

2020 ◽  
Vol 10 (2) ◽  
pp. 61-72
Author(s):  
John Karanikas ◽  
Guillermo Pastor ◽  
Scott Penny
Keyword(s):  
Heavy Oil ◽  
Horizontal Wells ◽  
Electric Heating ◽  
Optimization Method ◽  
Economic Benefits ◽  
Production Optimization ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Well ◽  
Heavy Oil Reservoirs

Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper. The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US. A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data.  The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures. Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.

Innovative Well-Completion Strategy for Challenging Heavy-Oil Wells within Mature Fields Requiring Sand Control in Colombia

2011 ◽  
Author(s):  
Ye Huimin ◽  
Mauricio Patarroyo ◽  
Carlos Alberto Perez Moreno ◽  
Nicolas Lopez
Keyword(s):  
Heavy Oil ◽  
Oil Wells ◽  
Well Completion ◽  
Sand Control

Preventing Proppant and Formation-Sand Production in High Water Cut, Heavy-Oil Wells: A Field Study from Argentina

2009 ◽  
Author(s):  
Daniel Daparo ◽  
Luis Soliz ◽  
Eduardo Roberto Perez ◽  
Carlos Iver Vidal Saravia ◽  
Philip Duke Nguyen ◽  
...  
Keyword(s):  
Field Study ◽  
Heavy Oil ◽  
High Water ◽  
Oil Wells ◽  
Sand Production ◽  
High Water Cut ◽  
Water Cut

scholarly journals Designing pressure build-up test on heavy oil well by alternating oil viscosity

2019 ◽  
Vol 1402 ◽  
pp. 022029 ◽  
Author(s):  
M T Fathaddin ◽  
R H K Oetomo ◽  
N Hisanah
Keyword(s):  
Heavy Oil ◽  
Oil Well ◽  
Oil Viscosity

DEPSO With DTCWT Algorithm for Multimodal Medical Image Fusion

2021 ◽  
Vol 12 (4) ◽  
pp. 78-97
Author(s):  
Hassiba Talbi ◽  
Mohamed-Khireddine Kholladi
Keyword(s):  
Wavelet Transform ◽  
Image Fusion ◽  
High Frequency ◽  
Medical Image ◽  
Low Frequency ◽  
Weighted Average ◽  
Optimization Method ◽  
Absolute Maximum ◽  
Complex Wavelet Transform ◽  
Medical Image Fusion

In this paper, the authors propose an algorithm of hybrid particle swarm with differential evolution (DE) operator, termed DEPSO, with the help of a multi-resolution transform named dual tree complex wavelet transform (DTCWT) to solve the problem of multimodal medical image fusion. This hybridizing approach aims to combine algorithms in a judicious manner, where the resulting algorithm will contain the positive features of these different algorithms. This new algorithm decomposes the source images into high-frequency and low-frequency coefficients by the DTCWT, then adopts the absolute maximum method to fuse high-frequency coefficients; the low-frequency coefficients are fused by a weighted average method while the weights are estimated and enhanced by an optimization method to gain optimal results. The authors demonstrate by the experiments that this algorithm, besides its simplicity, provides a robust and efficient way to fuse multimodal medical images compared to existing wavelet transform-based image fusion algorithms.

Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq

2021 ◽  
Author(s):  
Xueqing Tang ◽  
Ruifeng Wang ◽  
Zhongliang Cheng ◽  
Hui Lu
Keyword(s):  
High Pressure ◽  
Heavy Oil ◽  
Oil Quality ◽  
Oil Wells ◽  
Gas Condensate ◽  
Oil Viscosity ◽  
Foamy Oil ◽  
Artificial Lift ◽  
Water Coning ◽  
The Dead

Abstract Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved. Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.

A Superior Shale Oil EOR Method for the Permian Basin

2021 ◽  
Author(s):  
Robert Downey ◽  
Kiran Venepalli ◽  
Jim Erdle ◽  
Morgan Whitelock
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Simulation Modeling ◽  
Lower Cost ◽  
Oil Production ◽  
Oil Wells ◽  
Oil Well ◽  
Shale Oil ◽  
Permian Basin ◽  
Artificial Lift

Abstract The Permian Basin of west Texas is the largest and most prolific shale oil producing basin in the United States. Oil production from horizontal shale oil wells in the Permian Basin has grown from 5,000 BOPD in February, 2009 to 3.5 Million BOPD as of October, 2020, with 29,000 horizontal shale oil wells in production. The primary target for this horizontal shale oil development is the Wolfcamp shale. Oil production from these wells is characterized by high initial rates and steep declines. A few producers have begun testing EOR processes, specifically natural gas cyclic injection, or "Huff and Puff", with little information provided to date. Our objective is to introduce a novel EOR process that can greatly increase the production and recovery of oil from shale oil reservoirs, while reducing the cost per barrel of recovered oil. A superior shale oil EOR method is proposed that utilizes a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. The process is designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation modeling of a Wolfcamp D horizontal producing oil well was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate the shale oil EOR method under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation, and more than 700% over primary EUR after 10 years. The method, which is patented, has numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, lower risk of interwell communication, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions. This superior shale oil EOR method has been modeled in the five major US shale oil plays, indicating large incremental oil recovery potential. The method is now being field tested to confirm reservoir simulation modeling projections. If implemented early in the life of a shale oil well, its application can slow the production decline rate, recover far more oil earlier and at lower cost, and extend the life of the well by several years, while precluding the need for artificial lift.

Sand Control Strategy for Unconsolidated Sandstone Heavy Oil Reservoir in Kuwait

2018 ◽  
Author(s):  
Mahmoud Reda ◽  
Abdulaziz Erhama ◽  
Kerry Henderson ◽  
Yousef Al-Mulla ◽  
Tamadhor AlMuhanna
Keyword(s):  
Heavy Oil ◽  
Control Strategy ◽  
Oil Reservoir ◽  
Sand Control ◽  
Heavy Oil Reservoir

scholarly journals A modelling study of the event-based retention performance of green roof under the hot-humid tropical climate in Kuching

2017 ◽  
Vol 76 (11) ◽  
pp. 2988-2999 ◽  
Author(s):  
C. T. Chai ◽  
F. J. Putuhena ◽  
O. S. Selaman
Keyword(s):  
Flash Flood ◽  
Retention Rate ◽  
Meteorological Data ◽  
Green Roof ◽  
Tropical Climate ◽  
Climatic Conditions ◽  
Retention Performance ◽  
Strong Negative Correlation ◽  
Rainfall Depth ◽  
Event Based

Abstract The influences of climate on the retention capability of green roof have been widely discussed in existing literature. However, knowledge on how the retention capability of green roof is affected by the tropical climate is limited. This paper highlights the retention performance of the green roof situated in Kuching under hot-humid tropical climatic conditions. Using the green roof water balance modelling approach, this study simulated the hourly runoff generated from a virtual green roof from November 2012 to October 2013 based on past meteorological data. The result showed that the overall retention performance was satisfactory with a mean retention rate of 72.5% from 380 analysed rainfall events but reduced to 12.0% only for the events that potentially trigger the occurrence of flash flood. By performing the Spearman rank's correlation analysis, it was found that the rainfall depth and mean rainfall intensity, individually, had a strong negative correlation with event retention rate, suggesting that the retention rate increases with decreased rainfall depth. The expected direct relationship between retention rate and antecedent dry weather period was found to be event size dependent.

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