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.

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.

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).

Barrow Island enhanced oil recovery polymer pilot—part two: progress and way forward

2011 ◽  
Vol 51 (2) ◽  
pp. 672
Author(s):  
Daniel León ◽  
John Scott ◽  
Steven Saul ◽  
Lina Hartanto ◽  
Shannon Gardner ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Injection Pressure ◽  
Fracture Network ◽  
Oil Field ◽  
High Porosity ◽  
Polymer Injection ◽  
Fine Grained ◽  
Successful Design ◽  
Fit For Purpose ◽  
Water Cut

After successful design and implementation phases that included both subsurface and facilities components, an EOR polymer injection pilot has been operational for two years in Australia's largest onshore oil field at Barrow Island (816 MMstb OOIP). The pilot's main objective was to identify a suitable EOR technology for the complex, highly heterogeneous, very fine-grained, bioturbated argillaceous sandstone—high in glauconite, high porosity (∼23 %), low permeability (∼5 mD, with 50+ mD streaks)—reservoir that will ultimately increase the recovery of commercial resources past the estimated ultimate recovery factor with waterflooding (∼42 %). This was achieved using the in-depth flow diversion (IFD) methodology to access new unswept oil zones—both vertically and horizontally—by inducing growth in the fracture network. During the pilot operating phase, the main focus has been on surveillance and monitoring activities to assess the effectiveness of the process, including: injection pressure at the wellheads—indicating any increase in resistance to flow; pressure fall off tests at the injectors—to determine fracture growth, if any sampling and lab analysis at the producers—to identify polymer breakthrough; frequent production tests—quantifying reduction in water cut and oil production uplift; and, pressure build up surveys at the producers. These activities provided input data to the fit for purpose simulation model built in Reveal incorporating fractures and polymer as a fourth phase. With more than 96 % compliance to the surveillance plan, this paper will present the present findings and evaluation of the results, which may lead to the continuation of the pilot in other patterns of the reservoir and, possibly, to further expansion in the field.

Optimising Oil Field Net Present Value with Produced Water Salinities and Tracers

2021 ◽  
Author(s):  
Babalola Daramola
Keyword(s):  
Reservoir Simulation ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Oil Field ◽  
Water Flooding ◽  
Water Salinity ◽  
History Match ◽  
Infill Drilling ◽  
Salinity Data

Abstract This paper presents case studies of how produced water salinity data was used to transform the performance of two oil producing fields in Nigeria. Produced water salinity data was used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production. A reservoir simulation study was unable to history match the water cut in 3 production wells in Field B. Water salinity data enabled the asset team to estimate the arrival time of injected sea water at each production well in oil field B. This improved the reservoir simulation history match, increased model confidence, and validated the simulation model for the placement of infill drilling targets. The asset team also gained additional insight on the existing water flood performance, transformed the water flooding strategy, and added 9.6 MMSTB oil reserves. The asset team at Field C was unable to recover oil production from a well after it died suddenly. The team evaluated water salinity data, which suggested scale build up in the well, and completed a bottom-hole camera survey to prove the diagnosis. This justified a scale clean-out workover, and added 5000 barrels per day of oil production. A case study of how injection tracer data was used to characterise a water injection short circuit in Field D is also presented. Methods of using produced water salinity and injection tracer data to manage base production and add significant value to petroleum fields are presented. Produced water salinity and injection tracer data also simplify water injection connectivity evaluations, and can be used to justify test pipeline and test separator installation for data acquisition.

scholarly journals Chemical enhanced oil recovery and the dilemma of more and cleaner energy

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Rouhi Farajzadeh ◽  
Siavash Kahrobaei ◽  
Ali Akbari Eftekhari ◽  
Rifaat A. Mjeni ◽  
Diederik Boersma ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Energy Demand ◽  
Produced Water ◽  
Transition Period ◽  
Water Injection ◽  
Energy Transition ◽  
Polymer Injection ◽  
Water Fraction ◽  
Water Cut

AbstractA method based on the concept of exergy-return on exergy-investment is developed to determine the energy efficiency and CO2 intensity of polymer and surfactant enhanced oil recovery techniques. Exergy is the useful work obtained from a system at a given thermodynamics state. The main exergy investment in oil recovery by water injection is related to the circulation of water required to produce oil. At water cuts (water fraction in the total liquid produced) greater than 90%, more than 70% of the total invested energy is spent on injection and lift pumps, resulting in large CO2 intensity for the produced oil. It is shown that injection of polymer with or without surfactant can considerably reduce CO2 intensity of the mature waterflood projects by decreasing the volume of produced water and the exergy investment associated with its circulation. In the field examples considered in this paper, a barrel of oil produced by injection of polymer has 2–5 times less CO2 intensity compared to the baseline waterflood oil. Due to large manufacturing exergy of the synthetic polymers and surfactants, in some cases, the unit exergy investment for production of oil could be larger than that of the waterflooding. It is asserted that polymer injection into reservoirs with large water cut can be a solution for two major challenges of the energy transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO2 intensity of oil production (more and cleaner energy).

scholarly journals Interception Characteristics and Pollution Mechanism of the Filter Medium in Polymer-Flooding Produced Water Filtration Process

Processes ◽  
2019 ◽  
Vol 7 (12) ◽  
pp. 927
Author(s):  
Xingwang Wang ◽  
Xiaoxuan Xu ◽  
Wei Dang ◽  
Zhiwei Tang ◽  
Changchao Hu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Suspended Solids ◽  
Produced Water ◽  
Oil Pollution ◽  
Water Injection ◽  
Polymer Flooding ◽  
Oil Field ◽  
Filter Medium ◽  
Colloidal System ◽  
Oil Droplets

Polymer flooding enhances oil recovery, but during the application of this technology, it also creates a large amount of polymer-contained produced water that poses a threat to the environment. The current processing is mainly focused on being able to meet the re-injection requirements. However, many processes face the challenges of purifying effect, facilities pollution, and economical justification in the field practice. In the present work, to fully understand the structure and principle of the oil field filter tank, and based on geometric similarity and similar flow, a set of self-designed filtration simulation devices is used to study the treatment of polymer-contained produced water in order to facilitate the satisfaction of the water injection requirements for medium- and low-permeability reservoirs. The results show that, due to the existence of polymers in oil field produced water, a stable colloidal system is formed on the surface of the filter medium, which reduces the adsorption of oil droplets and suspended solids by the filter medium. The existence of the polymers also increases the viscosity of water, promotes the emulsification of oil pollution, and increases the difficulty of filtration and separation. As filtration progresses, the adsorption of the polymers by the filter medium bed reaches saturation, and the polymers and oil pollution contents in the filtered water increase gradually. The concentration and particle size of the suspended solids eventually exceed the permissible standards for filtered water quality; this is mainly due to the unreasonable size of the particle in relation to the filter medium gradation and the competitive adsorption between the polymers and the suspended solids on the surface of the filter medium. The oil concentration of the filtered water also exceeds the allowable standards and results from the polymers replace the oil droplets in the pores and on the surfaces of the filter medium. Moreover, the suspended particles of the biomass, composed of dead bacteria, hyphae, and spores, have strong attachment and carrying ability with respect to oil droplets, which cause the suspended solids in the filtered water to exceed the permissible standards and oil droplets to be retained in the filtered effluent at the same time.

Successful Implementation of Polymer Flood in Aishwariya Field, Rajasthan, India - Concept to Full Field

2021 ◽  
Author(s):  
Aditya Kumar Singh ◽  
Pruthvi Raju Vegesna ◽  
Dhruva Prasad ◽  
Saideep Chandrashekar Kachodi ◽  
Sumit Lohiya ◽  
...  
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Surveillance Program ◽  
Successful Implementation ◽  
Reservoir Properties ◽  
Solution Quality ◽  
Full Field ◽  
Polymer Injection ◽  
Polymer Flood ◽  
Water Cut

Abstract The Aishwariya Oil Field located in Barmer Basin of Rajasthan India having STOIIP of ∼300 MMBBLS was initially developed with down-dip edge water injection. The main reservoir unit, Fatehgarh Formation, has excellent reservoir characteristics with porosities of 20-30% and permeability of 1 to 5 Darcys. The Fatehgarh Formation is subdivided into Lower Fatehgarh (LF) and Upper Fatehgarh (UF) Formations, of which LF sands are more homogenous and have slightly better reservoir properties. The oil has in-situ viscosity of 10-30 cP. Given its adverse waterflood mobility ratio, the importance of EOR was recognised very early. Initial screening studies identified that chemical EOR (polymer and ASP) was preferred choice of EOR process. Extensive lab studies and simulation work was conducted to develop the polymer flood concept. A polymer flood development plan was prepared targeting the LF sands of the field utilizing the lessons learnt from nearby Mangala Field polymer implementation project. The polymer flood in Aishwariya Field was implemented in two stages. In the first stage, a polymer injectivity test was conducted in 3 wells to establish the potential for polymer injection in these wells. The injection was extended to 3 more wells and continued for ∼4 years. Significant water cut drop was observed in nearby wells during this phase of polymer injection. In the next stage, polymer flooding was extended to the entire LF sands with drilling of 14 new infill wells and conversion of 8 existing wells to polymer injectors. A ∼14 km long pipeline was laid from the Mangala Central Polymer Facility to well pads in the field to cater to the requirement of 6-8 KBPD of ∼15000 ppm polymer mother solution. The philosophy of pre-production for extended periods was considered prior to start of polymer injection for all wells as it significantly improved injection (reduced skin) and conformance. Full field polymer flood project was implemented, and injection was ramped up to the planned 40-50 KBPD of polymerized water within a month owing to good injectivity and polymer solution quality. A detailed laboratory, well and reservoir surveillance program has been implemented and the desired wellhead viscosity of 25-30 cP has been achieved. Initial response shows significant increase in oil production rate and decrease in water-cut. This paper presents the polymer laboratory studies, initial long term injectivity test results, polymer flood development concept and planning, simulation studies and field implementation in LF Formation in Aishwariya Field.

The Birch Field, Block 16/12a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 167-181 ◽  
Author(s):  
J. Hook ◽  
A. Abhvani ◽  
J. G. Gluyas ◽  
M. Lawlor
Keyword(s):  
Hanging Wall ◽  
Water Injection ◽  
Oil Production ◽  
Volatile Oil ◽  
Oil Field ◽  
Injection Well ◽  
Current Estimate ◽  
Oil Reserves ◽  
Water Cut ◽  
The Uk

AbstractThe Birch Field is an oil field located in Block 16/12a on the UK Continental Shelf (UKCS) and is part of the well-established 'Brae Trend'. Birch produces an undersaturated volatile oil from the Brae Conglomerate, a locally thick conglomeratic unit within the Late Jurassic Brae Formation. The reservoir was deposited as a small submarine fan in the hanging wall of the main fault bounding the western side of the South Viking Graben. The current estimate for oil in place is about 70MMSTB with expected ultimate oil reserves of 30MMSTB. The field was brought on stream in September 1995 as a phased waterflood subsea development, tied back to Marathon's Brae 'A' platform in neighbouring Block 16/7a. During Phase I the discovery and both appraisal wells were re-completed as two oil producers and one water injection well. Phase II comprised a third oil production well and a second water injection well drilled and completed in 1996-1997. Oil production peaked at c. 28 000 BOPD in the second half of 1996. The field is currently in decline and production in June 1999 was c. 7000 BOPD with a water-cut of c. 40%. Cumulative oil production to end June 1999 was 21 MM STB and remaining oil reserves are estimated as 9MMSTB.

scholarly journals New Waterflooding Characteristic Curves Based on Cumulative Water Injection

2020 ◽  
Vol 2020 ◽  
pp. 1-12
Author(s):  
Zhiwang Yuan ◽  
Zhiping Li ◽  
Li Yang ◽  
Yingchun Zhang
Keyword(s):  
Characteristic Curve ◽  
Water Injection ◽  
Material Balance ◽  
Oil Production ◽  
High Water ◽  
Difficult Problem ◽  
Prediction Errors ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
Water Cut

When a conventional waterflooding characteristic curve (WFCC) is used to predict cumulative oil production at a certain stage, the curve depends on the predicted water cut at the predicted cutoff point, but forecasting the water cut is very difficult. For the reservoirs whose pressure is maintained by water injection, based on the water-oil phase seepage theory and the principle of material balance, the equations relating the cumulative oil production and cumulative water injection at the moderately high water cut stage and the ultrahigh water cut stage are derived and termed the Yuan-A and Yuan-B curves, respectively. And then, we theoretically analyze the causes of the prediction errors of cumulative oil production by the Yuan-A curve and give suggestions. In addition, at the ultrahigh water cut stage, the Yuan-B water cut prediction formula is established, which can predict the water cut according to the cumulative water injection and solve the difficult problem of water cut prediction. The application results show Yuan-A and Yuan-B curves are applied to forecast oil production based on cumulative water injection data obtained by the balance of injection and production, avoiding reliance on the water cut forecast and solving the problems of predicting the cumulative oil production of producers or reservoirs that have not yet shown the decline rule. Furthermore, the formulas are simple and convenient, providing certain guiding significance for the prediction of cumulative oil production and water cut for the same reservoir types.

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