Review of Practical Experience by Polymer Flooding at Daqing

2009 ◽  
Vol 12 (03) ◽  
pp. 470-476 ◽  
Author(s):  
Dongmei Wang ◽  
Huanzhong Dong ◽  
Changsen Lv ◽  
Xiaofei Fu ◽  
Jun Nie
Keyword(s):  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Molecular Weights ◽  
Well Spacing ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut

Summary This paper describes successful practices applied during polymer flooding at Daqing that will be of considerable value to future chemical floods, both in China and elsewhere. On the basis of laboratory findings, new concepts have been developed that expand conventional ideas concerning favorable conditions for mobility improvement by polymer flooding. Particular advances integrate reservoir-engineering approaches and technology that is basic for successful application of polymer flooding. These include the following:Proper consideration must be given to the permeability contrast among the oil zones and to interwell continuity, involving the optimum combination of oil strata during flooding and well-pattern design, respectively;Higher polymer molecular weights, a broader range of polymer molecular weights, and higher polymer concentrations are desirable in the injected slugs;The entire polymer-flooding process should be characterized in five stages--with its dynamic behavior distinguished by water-cut changes; -Additional techniques should be considered, such as dynamic monitoring using well logging, well testing, and tracers; effective techniques are also needed for surface mixing, injection facilities, oil production, and produced-water treatment; andContinuous innovation must be a priority during polymer flooding. Introduction China's Daqing oil field entered its ultrahigh-water-cut period after 30 years of exploitation. Just before large-scale polymer-flooding application, the average water-cut was more than 90%. The Daqing oil-field is a large river-delta/lacustrine facies, multilayered with complex geologic conditions and heterogeneous sandstone in an inland basin. After 30 years of waterflooding, many channels and high-permeability streaks were identified in this oil field (Wang and Qian 2002). Laboratory research began in the 1960s, investigating the potential of enhanced-oil-recovery (EOR) processes in the Daqing oil field. After a single-injector polymer flood with a small well spacing of 75 m in 1972, polymer flooding was set on pilot test. During the late 1980s, a pilot project in central Daqing was expanded to a multiwell pattern with larger well spacing. Favorable results from these tests--along with extensive research and engineering from the mid-1980s through the 1990s--confirmed that polymer flooding was the preferred method to improve areal- and vertical-sweep efficiency at Daqing and to provide mobility control (Wang et al. 2002, Wang and Liu 2004). Consequently, the world's largest polymer flood was implemented at Daqing, beginning in 1996. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding boosted the ultimate recovery for the field to more than 50% of original oil in place (OOIP)--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 10 million tons (73 million bbl) per year (sustained for 6 years). The focus of this paper is on polymer flooding, in which sweep efficiency is improved by reducing the water/oil mobility ratio in the reservoir. This paper is not concerned with the use of chemical gel treatments, which attempt to block water flow through fractures and high-permeability strata. Applications of chemical gel treatments in China have been covered elsewhere (Liu et al. 2006).

Key Aspects of Project Design for Polymer Flooding at the Daqing Oilfield

2008 ◽  
Vol 11 (06) ◽  
pp. 1117-1124 ◽  
Author(s):  
Dongmei Wang ◽  
Randall S. Seright ◽  
Zhenbo Shao ◽  
Jinmei Wang
Keyword(s):  
Molecular Weight ◽  
Polymer Concentration ◽  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
Polymer Injection ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut ◽  
Injection Rates

Summary This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field. Special emphasis is placed on some new design factors that were found to be important on the basis of extensive experience with polymer flooding. These factors include (1) recognizing when profile modification is needed before polymer injection and when zone isolation is of value during polymer injection, (2) establishing the optimum polymer formulations and injection rates, and (3) time-dependent variation of the molecular weight of the polymer used in the injected slugs. For some Daqing wells, oil recovery can be enhanced by 2 to 4% of original oil in place (OOIP) with profile modification before polymer injection. For some Daqing wells with significant permeability differential between layers and no crossflow, injecting polymer solutions separately into different layers improved flow profiles, reservoir sweep efficiency, and injection rates, and it reduced the water cut in production wells. Experience over time revealed that larger polymer-bank sizes are preferred. Bank sizes grew from 240-380 mg/L·PV during the initial pilots to 640 to 700 mg/L·PV in the most recent large-scale industrial sites [pore volume (PV)]. Economics and injectivity behavior can favor changing the polymer molecular weight and polymer concentration during the course of injecting the polymer slug. Polymers with molecular weights from 12 to 35 million Daltons were designed and supplied to meet the requirements for different reservoir geological conditions. The optimum polymer-injection volume varied around 0.7 PV, depending on the water cut in the different flooding units. The average polymer concentration was designed approximately 1000 mg/L, but for an individual injection station, it could be 2000 mg/L or more. At Daqing, the injection rates should be less than 0.14-0.20 PV/year, depending on well spacing. Introduction Many elements have long been recognized as important during the design of a polymer flood (Li and Niu 2002; Jewett and Schurz 1970; Sorbie 1991; Vela et al. 1976; Taber et al. 1997; Maitin 1992; Koning et al. 1988; Wang et al. 1995; Wang and Qian 2002; Wang et al. 2008). This paper spells out some of those elements, using examples from the Daqing oil field. The Daqing oil field is located in northeast China and is a large river-delta/lacustrine-facies, multilayer, heterogeneous sandstone in an inland basin. The reservoir is buried at a depth of approximately 1000 m, with a temperature of 45°C. The main formation under polymer flood (i.e., the Saertu formation) has a net thickness ranging from from 2.3 to 11.6 m with an average of 6.1 m. The average air permeability is 1.1 µm2, and the Dykstra-Parsons permeability coefficient averages 0.7. Oil viscosity at reservoir temperature averages approximately 9 mPa·s, and the total salinity of the formation water varies from 3000 to 7000 mg/L. The field was discovered in 1959, and a waterflood was initiated in 1960. The world's largest polymer flood was implemented at Daqing, beginning in December 1995. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding should boost the ultimate recovery for the field to more than 50% OOIP--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 11.6 million m3 (73 million bbl) per year (sustained for 6 years). The polymers used at Daqing are high-molecular-weight partially hydrolyzed polyacrylamides (HPAMs). During design of a polymer flood, critical reservoir factors that traditionally receive consideration are the reservoir lithology, stratigraphy, important heterogeneities (such as fractures), distribution of remaining oil, well pattern, and well distance. Critical polymer properties include cost-effectiveness (e.g., cost per unit of viscosity), resistance to degradation (mechanical or shear, oxidative, thermal, microbial), tolerance of reservoir salinity and hardness, retention by rock, inaccessible pore volume, permeability dependence of performance, rheology, and compatibility with other chemicals that might be used. Issues long recognized as important for polymer-bank design include bank size (volume), polymer concentration and salinity (affecting bank viscosity and mobility), and whether (and how) to grade polymer concentrations in the chase water. This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field.

Adaptability Study on Plugging Thief Zones with Asphalt Particle in Polymer Flooding Offshore Field

2014 ◽  
Author(s):  
K.. Xiao ◽  
H.. Jiang ◽  
Q.. Wang ◽  
H.. Wang ◽  
D.. Zhao
Keyword(s):  
Numerical Model ◽  
Numerical Simulations ◽  
Oil Recovery ◽  
Negative Impact ◽  
Oil Production ◽  
Polymer Flooding ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Water Cut ◽  
Offshore Field

Abstract Polymer flooding has been proved to be an effective method for improving oil recovery in offshore field of Bohai area, but thief zones with high permeability could make the effect of polymer on oil production worse. To try to minimize the negative impact brought by thief zones, we apply asphalt particle to plug the high permeability regions to compel subsequent displacement fluid change flowing direction to enhance sweep efficiency. Its adaptability is studied by a series of parallel cores flooding. Besides, numerical simulations are carried out to optimize pattern of asphalt particle injection and evaluate the performances of asphalt flooding in a typical well group in Bohai area in a numerical model. In addition to performances of water cut and oil recovery for the parallel core flooding, we present dynamic features of remaining oil from micro views detected by nuclear magnetic resonance. By plugging thief zone by asphalt flooding, oil production is improved. Production in small and medium pores is increased by asphalt flowing into big pores to exert strong resistance on them. Also, with numerical simulations, optimal way of injecting asphalt has been selected to lead the operation in field. Through observation of a typical well group under asphalt injection in numerical model based on real reservoir, the water-cut and oil production are decrease 9.7% and increase 29.1m3/d respectively. We conclude that asphalt particle has good capacity to plug thief zones to improve sweep efficiency of subsequent displacement fluid in polymer flooding field. In-depth understanding such mechanisms for asphalt particle behavior may be pivotal for enhancing oil recovery in polymer flooding reservoir containing thief zones.

Polymer-Flooding-Pilot Learning Curve: Five-Plus Years' Experience To Reduce Cost per Incremental Barrel of Oil

2014 ◽  
Vol 18 (01) ◽  
pp. 11-19 ◽  
Author(s):  
J.. Buciak ◽  
G.. Fondevila Sancet ◽  
L.. Del Pozo
Keyword(s):  
Learning Curve ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Porosity ◽  
Polymer Injection ◽  
Injection Pump ◽  
Water Cut

Summary This paper deals with the learning curve of a five-plus-year polymer-flooding pilot conducted in a mature waterflood that includes, for example, several works related to injector and producer wells and reservoir management. The scope of this paper is to describe the learning curve during the last 5 years rather than the reservoir response of the polymer-flooding technique; focus is on the aspects related to reduce cost per incremental barrel of oil for a possible extension to other waterflooded areas of the field. Diadema oil field is in the San Jorge Gulf basin in the southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil-producer company; it has 480 producer and 270 injector wells (interwell spacing is 250 m on average). The company has developed waterflooding over more than 18 years (today, this technique represents 82% of oil production in the field) and produces approximately 1600 m3/d of oil and 40 000 m3/d of gross production (96% water cut) with 38 400 m3/d of water injection. The reservoir that is polymer-flooded is characterized by high permeability (average of 500 md), high heterogeneity (10 to 5,000 md), high porosity (30%), very stratified sandstone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp at reservoir conditions). Diadema's polymer-flooding pilot started in October 2007 on five water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made with produced water (15,000 ppm brine) and 1,500 ppm of hydrolyzed polyacrylamide polymer reaching 15- to 20-cp fluid-injection viscosity. Oil-production rate from the original “central” producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is approximately 15%. The main aspects presented in this work are depth profile modification with crosslinked gel injected along with polymer, use of “curlers” to regulate injection in multiple wells with one injection pump without shearing the polymer, and an improved technology on producer wells with progressing-cavity pumps to decrease shut-in time and number of pump failures. The plan for the future is to extend this project to other areas with the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation. These improvements will allow the company to reduce operating costs per incremental barrel of oil.

Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Technology in Daqing Oilfield

2006 ◽  
Vol 9 (06) ◽  
pp. 664-673 ◽  
Author(s):  
Harry L. Chang ◽  
Xingguang Sui ◽  
Long Xiao ◽  
Zhidong Guo ◽  
Yuming Yao ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Colloidal Dispersion ◽  
Oil Field ◽  
Sweep Efficiency ◽  
Profile Modification ◽  
Production Wells ◽  
Daqing Oil Field ◽  
Incremental Oil Recovery ◽  
Water Cut ◽  
Weak Gels

Summary The first large-scale colloidal dispersion gel (CDG) pilot test was conducted in the largest oil field in China, Daqing oil field. The project was initiated in May 1999, and injection of chemical slugs was completed in May 2003. This paper provides detailed descriptions of the gel-system characterization, chemical-slug optimization, project execution, performance analysis, injection facility design, and economics. The improvements of permeability variation and sweep efficiency were demonstrated by lower water cut, higher oil rate, improved injection profiles, and the increase of the total dissolved solids (TDS) in production wells. The ultimate incremental oil recovery (defined as the amount of oil recovered above the projected waterflood recovery at 98% water cut) in the pilot area would be approximately 15% of the original oil in place (OOIP). The economic analysis showed that the chemical costs were approximately U.S. $2.72 per barrel of incremental oil recovered. Results are presented in 15 tables and 8 figures. Introduction Achieving mobility control by increasing the injection fluid viscosity and achieving profile modification by adjusting the permeability variation in depth are two main methods of improving the sweep efficiency in highly heterogeneous and moderate viscous-oil reservoirs. In recent years (Wang et al. 1995, 2000, 2002; Guo et al. 2000), the addition of high-molecular-weight (MW) water-soluble polymers to injection water to increase viscosity has been applied successfully in the field on commercial scales. Weak gels, such as CDGs, formed with low-concentration polymers and small amounts of crosslinkers such as the trivalent cations aluminum (Al3+) and chromium (Cr3+) also have been applied successfully for in-depth profile modification (Fielding et al. 1994; Smith 1995; Smith and Mack 1997). Typical behaviors of CDGs and testing methods are given in the literature (Smith 1989; Ranganathan et al. 1997; Rocha et al. 1989; Seright 1994). The giant Daqing oil field is located in the far northeast part of China. The majority of the reservoir belongs to a lacustrine sedimentary deposit with multiple intervals. The combination of heterogeneous sand layers [Dykstra-Parsons (1950) heterogeneity indices above 0.5], medium oil viscosities (9 to 11 cp), mild reservoir temperatures (~45°C), and low-salinity reservoir brines [5,000 to 7,000 parts per million (ppm)] makes it a good candidate for chemical enhanced-oil-recovery processes. Daqing has successfully implemented commercial-scale polymer flooding (PF) since the early 1990s (Chang et al. 2006). Because the PF process is designed primarily to improve the mobility ratio (Chang 1978), additional oil may be recovered by using weak gels to further improve the vertical sweep. Along with the successes of PF in the Daqing oil field, two undesirable results were also observed:high concentrations of polymer produced in production wells owing to the injection of large amounts of polymer (~1000 ppm and 50% pore volume) andthe fast decline in oil rates and increase in water cuts after polymer injection was terminated. In 1997, a joint laboratory study between the Daqing oil field and Tiorco Inc. was conducted to investigate the potential of using the CDG process, or the CDG process with PF, to further improve the recovery efficiency, lower the polymer production in producing wells, and prolong the flood life. The joint laboratory study was completed in 1998 with encouraging results (Smith et al. 2000). Additional laboratory studies to further characterize the CDG gellation process, optimize the formulation, and investigate the degradation mechanisms were conducted in the Daqing field laboratories before the pilot test. A simplistic model was used to optimize the slug designs and predict incremental oil recovery. Initial designs called for a 25% pore volume (Vp) CDG slug with 700 ppm polymer and the polymer-to-crosslinker ratio (P/X) of 20 in a single inverted five-spot patten. Predicted incremental recovery was approximately 9% of OOIP.

New Gel Aggregates To Improve Sweep Efficiency During Waterflooding

2011 ◽  
Vol 14 (01) ◽  
pp. 120-128 ◽  
Author(s):  
Guanglun Lei ◽  
Lingling Li ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Low Cost ◽  
Oil Production ◽  
High Water ◽  
Resistance Factor ◽  
Water Production ◽  
Sweep Efficiency ◽  
Low Viscosity ◽  
Productivity Decline ◽  
High Water Cut ◽  
Water Cut

Summary A common problem for oil production is excessive water production, which can lead to rapid productivity decline and significant increases in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injectors, the injection profiles are uneven and, as a result, large amounts of oil are left behind the water front. Many chemical systems have been used to control water production and improve recovery from reservoirs with high water cut. Inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or crosslinked gels, especially polyacrylamide-based systems, are mainly used because of their relatively low cost and their supposed selectivity. In this paper, microspheres (5–30 μm) were synthesized using acrylamide monomers crosslinked with an organic crosslinker. They can be suspended in water and can be pumped in sandstone formations. They can plug some of the pore throats and, thus, force injected water to change its direction and increase the sweep efficiency. A high-pressure/high-temperature (HP/HT) rheometer was used to measure G (elastic modulus) and G" (viscous modulus) of these aggregates. Experimental results indicate that these microspheres are stable in solutions with 20,000 ppm NaCl at 175°F. They can expand up to five times their original size in deionized water and show good elasticity. The results of sandpack tests show that the microspheres can flow through cores with permeability greater than 500 md and can increase the resistance factor by eight to 25 times and the residual resistance factor by nine times. The addition of microspheres to polymer solutions increased the resistance factor beyond that obtained with the polymer solution alone. Field data using microspheres showed significant improvements in the injection profile and enhancements in oil production.

An Alkaline Bio-Surfactant Polymer Flooding Pilots in Daqing Oil Field

1999 ◽  
Author(s):  
Wang Demin ◽  
Cheng Jiecheng ◽  
Li Qun ◽  
Li Lizhong ◽  
Zhao Changjiu
Keyword(s):  
Polymer Flooding ◽  
Oil Field ◽  
Daqing Oil Field

The Mechanism of PCP Wells' Tubing and Rod Wear Issue in Polymer Flooding in Daqing Oil Field

2008 ◽  
Author(s):  
He Liu ◽  
Pei Xiaohan ◽  
Peng Baiqi ◽  
Hou Yu ◽  
Wang Yumei ◽  
...  
Keyword(s):  
Polymer Flooding ◽  
Oil Field ◽  
Daqing Oil Field

Pilot Test of Alkaline Surfactant Polymer Flooding in Daqing Oil Field

1997 ◽  
Vol 12 (04) ◽  
pp. 229-233 ◽  
Author(s):  
Wang Demin ◽  
Zhang Zhenhua ◽  
Cheng Jiecheng ◽  
Yang Jingchun ◽  
Gao Shutang ◽  
...  
Keyword(s):  
Polymer Flooding ◽  
Oil Field ◽  
Pilot Test ◽  
Daqing Oil Field ◽  
Alkaline Surfactant Polymer
Sign in / Sign up

Export Citation Format

Share Document