Technical Brief

Feasibility of Waterflooding for a Carbonate Oil Field Through Whole-Field Simulation Studies

[+] Author and Article Information
Wenting Yue

Petroleum and Natural Gas Engineering Program,
John and Willie Leone Family
Department of Energy and Mineral Engineering,
The Pennsylvania State University,
University Park, PA 16802
e-mail: wyy5019@psu.edu

John Yilin Wang

Petroleum and Natural Gas Engineering Program,
Department of Energy and Mineral Engineering
and EMS Energy Institute,
The Pennsylvania State University,
202 Hosler Building,
University Park, PA 16802
e-mail: john.wang@psu.edu

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received February 20, 2015; final manuscript received February 24, 2015; published online May 11, 2015. Editor: Hameed Metghalchi.

J. Energy Resour. Technol 137(6), 064501 (Nov 01, 2015) (8 pages) Paper No: JERT-15-1074; doi: 10.1115/1.4030401 History: Received February 20, 2015; Revised February 24, 2015; Online May 11, 2015

The carbonate oil field studied is a currently producing field in U.S., which is named “PSU” field to remain anonymity. Discovered in 1994 with wells on natural flow or through artificial lift, this field had produced 17.8 × 106 bbl of oil to date. It was noticed that gas oil ratio had increased in certain parts and oil production declined with time. This study was undertaken to better understand and optimize management and operation of this field. In this brief, we first reviewed the geology, petrophysical properties, and field production history of PSU field. We then evaluated current production histories with decline curve analysis, developed a numerical reservoir model through matching production and pressure data, then carried out parametric studies to investigate the impact of injection rate, injection locations, and timing of injection, and finally developed optimized improved oil recovery (OIR) methods based on ultimate oil recovery and economics. This brief provides an addition to the list of carbonate fields available in the petroleum literature and also improved understandings of Smackover formation and similar analogous fields. By documenting key features of carbonated oil field performances, we help petroleum engineers, researchers, and students understand carbonate reservoir performances.

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Grahic Jump Location
Fig. 1

A map of structure, approximate limit of Smackover deposition, and the location of PSU field (modified from SOGBA)

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Fig. 2

Upper Jurassic (Oxfordian) Smackover sequence stratigraphy for the target field [2]

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Fig. 3

Structural cross section AA, illustrating elevation changes in the PSU field area in a southwest to northeast direction [2]

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Fig. 4

Histograms illustrating the petrophysical properties of the lower (S-6) reservoirs as determined from well-log analysis and modeling at PSU field: (C) S-6 porosity, 267,425 samples, and S-6 permeability [1]

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Fig. 5

A representative well log of PSU field lower reservoir (courteous of operating company)

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Fig. 6

Profiles of oil rate (upper left), cumulative oil (upper right), gas rate (middle left), cumulative gas (middle right), GOR value (lower left) for PSU field lower reservoir

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Fig. 7

Decline exponent b values of individual wells mapped over lower reservoir in PSU field

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Fig. 8

Well location and thickness of the lower formation of PSU field in both 3D and 2D (courtesy of the operating company, 2009)

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Fig. 9

Oil–water and oil–gas relative permeability data (data courtesy of operator)

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Fig. 10

History matched oil rate and predicted cumulative oil recovery

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Fig. 11

Pressure (left) and oil saturation (right) maps after 10 yr in the lower formation of PSU field

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Fig. 12

3:1 line-drive patterns tested

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Fig. 13

Oil saturation map (left) and pressure map (right) of with injection rate of 4000 bbl/day/well on 2028-12–30

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Fig. 14

Cumulative oil recovery of varied injection rate based on same injection pattern (3:1 line drive)

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Fig. 15

Top view of PSU field showing well locations before and after infill drilling. Zoomed area shows driveline, first line of producers, and second line of producers.

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Fig. 16

Cumulative oil recovery (left) and watercut (right) of models with infill drilling and varied injection rates. These models are compared with natural depletion (no infill drill and no injection) and the best case in Fig. 14 (before infill drilling qin = 3000 bbl/D/well).

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Fig. 17

Cumulative oil recovery and watercut of with and without a watercut constraint of 90% at producers

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Fig. 18

Vertical view of PSU field showing 3:1 line drive (left) and hybrid drive (right)

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Fig. 19

Cumulative oil recovery and watercut of models with hybrid drive pattern (various injection rates) compared with base case. All models are based on infill-drilled field. The time that the entire field reaches 0.9 of watercut is marked with round dots on the cumulative oil plot.



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