Compaction and Dilation Effects on Polymer Flood Performance

Wang, D.; Seright, R.S.; Let, K. Moe Soe; Bhoendie, K.; Paidin, W.R.

doi:10.3997/2214-4609.201701590

Cited by 4 publications

(9 citation statements)

References 0 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Effect of Vertical Fractures. For our purposes, fractures in injection wells can be put in one of two basic categories: (1) those oriented perpendicular to the desired direction of flow (between and injector and producer, as in Figures 4(a)) and (2) those oriented parallel to the desired direction of flow (as in Figure 4(b)).…”

Section: Multiple Layers With Crossflowmentioning

confidence: 99%

“…During primary production, ~20% OOIP was recovered, by solution-gas and compaction drive. Polymer pilots were developed using vertical wells in 5-spot patterns with ~135-meter spacing [1,16,17,35,62,63]. The pilot area was described by permeability of 4-12 Darcies and two beds (T1 and T2) with a 12: 1 permeability contrast (free crossflow, 20 ft thickness for the most-permeable layer and 15 ft thickness for the second layer).…”

Section: Geofluidsmentioning

confidence: 99%

“…Unfortunately, injection of the more viscous polymer solutions did not improve performance of the polymer flood. The reasons for this have been debated [1,16,17], but one possibility raised was that pressure barriers may have been created during injection of the more viscous polymer solutions.…”

Section: Geofluidsmentioning

confidence: 99%

“…Ironically, no issues associated with reduced polymer injectivity or excessive fracture extension (leading to channeling) were noted at Daqing [4]. At Tambaredjo (Suriname, ~600 cp oil), field tests injecting polymer viscosities up to 165-cp did not appear to improve displacement efficiency (over 45 cp polymer)-for reasons that are still being debated [1,16,17]. Concerns about the impact of a pressure modification (associated with the polymer bank) have influenced the decisions made during most of these field applications.…”

Section: Introductionmentioning

confidence: 97%

“…Also, during a polymer flood, much of the injected polymer may be wasted by entering the gas cap or aquifer. Compaction has provided a drive energy in rare cases (e.g., Tambaredjo oil field in Suriname, [1]) but has a small effect in most reservoirs. For most polymer floods, the injected polymer bank is intended to provide the drive energy to efficiently displace the oil.…”

Section: Introductionmentioning

confidence: 99%

See 4 more Smart Citations

Pressure Modification or Barrier Issues during Polymer Flooding Enhanced Oil Recovery

2022

View full text Add to dashboard Cite

Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drops from the injection well to the polymer front may act as a pressure modification or barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity. This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Analytical and numerical methods are used to address this issue. We examine the relevance of the pressure modification concept for a wide variety of circumstances, including oil viscosities ranging from 10 cp to 1650 cp, vertical wells versus horizontal wells, single versus multiple layered reservoirs, permeability contrast, and crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multizoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors intervene. For multizoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. This work is particularly relevant to viscous oil reservoirs where polymer viscosities are substantially lower than the oil viscosity.

show abstract

Section: Multiple Layers With Crossflowmentioning

confidence: 99%

Section: Geofluidsmentioning

confidence: 99%

Section: Geofluidsmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 97%

Section: Introductionmentioning

confidence: 99%

See 3 more Smart Citations

Pressure Modification or Barrier Issues during Polymer Flooding Enhanced Oil Recovery

2022

View full text Add to dashboard Cite

show abstract

Adaptability Study of Hot Water Chemical Flooding in Offshore Heavy Oilfields

et al. 2022

View full text Add to dashboard Cite

As a new heavy oil development technology, hot water chemistry flooding has great potential in offshore heavy oil fields development. In this paper, the adaptability of hot water chemical flooding was studied based on the typical model of offshore heavy oil fields. The main controlling factors affecting the hot water chemical flooding were analyzed and evaluated by single factor analysis. The technical boundary was established for offshore heavy oil fields. In addition, the hot water chemical flooding scheme was designed by a case study of a well group oilfield D. The results indicate that crude oil viscosity and well spacing have great influences on hot water chemical flooding performance. Hot water chemical flooding is favorable when the crude oil viscosity is between 300 and 1000 mPa·s and well spacing is around 200~400 m. The hot water chemical flooding scheme of the target well group results in 40.2 × 10 4 tons of incremental oil, and 6.3% of recovery factor being enhanced, which shows strong evidence that hot water chemical flooding enables great oilfield development performance.

show abstract

Alkaline-Surfactant-Polymer Flooding: Where is the Enhanced Oil Exactly?

Yang

Jiang

et al. 2018

Day 3 Wed, March 28, 2018

View full text Add to dashboard Cite

With the advantages of high sweep efficiency and displacement efficiency, alkaline-surfactant-polymer (ASP) flooding can greatly improve the oil recovery by 20%. The microscopic displacement mechanisms have been reported in detail, however, the macroscopic 3D fluid flow characteristics still lack enough research. This paper is aimed to study the macroscopic flow dynamics in ASP and further clarify the distinctions of remaining oil saturation between waterflooding and chemical flooding. The flow dynamics were examined at both laboratory and numerical scale. A sandpack physical model was designed to simulate the vertical heterogeneous reservoir. To analyze the pressure distribution during the ASP flooding, the model was equipped with 25 pressure transducers. Then we built the corresponding numerical model to simulate the ASP process. Basic experiments data were used for history match and chemical parameters. In the simulation, we investigated the base case (pure waterflooding) and seven chemical flooding scenarios (alkali, surfactant, polymer, alkali-surfactant, alkali-polymer, surfactant-polymer, alkali-surfactant-polymer flooding, respectively). "Enhanced oil saturation (EOS)" is defined by subtracting each chemical flooding from waterflooding case. The distribution maps/profiles were generated for comparison in eight cases. Viewed from the x-y areal plane, in the cases added with polymer, the injected chemicals from main streamline were observed to gradually spread to the two sides apart to displace the remaining oil. Besides, chemicals were diverted into lower permeability at vertical section. Based on the saturation profile presented in each chemical flooding scenarios, we classified the enhanced oil area into 4 subzones: A-zone, S-zone, P-zone and ASP-zone. This division characterized both individual and synergistic effects in alkali, surfactant, and polymer. Sensitivity analysis was conducted to compare the influence of alkali, surfactant, and polymer with different concentrations on the area where oil was extracted. Results show that: (1) as the polymer concentration grew higher, all the sub-zones displayed increasing tendency, but the impact would diminish if the concentration exceeded 1500 mg/L; (2) a relatively rich surfactant-bearing solution helped expand P-zone, and the ASP-zone is also benefited; (3) an optimal alkali concentration is advised to be 1% ~1.5%. We establish a comprehensive characterization of the fluid flow dynamics by performing physical experiments and numerical simulation. The novelty of the paper is the inspection on the location where extra oil is driven by the function of each component. The synergy in ASP is recognized by pressure and saturation distribution. The study provides a better understanding of macroscopic flow mechanisms in chemical flooding projects.

show abstract

Compaction and Dilation Effects on Polymer Flood Performance

Cited by 4 publications

References 0 publications

Pressure Modification or Barrier Issues during Polymer Flooding Enhanced Oil Recovery

Pressure Modification or Barrier Issues during Polymer Flooding Enhanced Oil Recovery

Adaptability Study of Hot Water Chemical Flooding in Offshore Heavy Oilfields

Alkaline-Surfactant-Polymer Flooding: Where is the Enhanced Oil Exactly?

Contact Info

Product

Resources

About