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Title: A new correlation to evaluate the fracture permeability changes as reservoir is depleted

Authors:
; ; ; ;
Publication Date:
Sponsoring Org.:
USDOE
OSTI Identifier:
1359735
Grant/Contract Number:
FC26-08NT0005643; EPS-0814442
Resource Type:
Journal Article: Publisher's Accepted Manuscript
Journal Name:
Journal of Petroleum Science and Engineering
Additional Journal Information:
Journal Volume: 145; Journal Issue: C; Related Information: CHORUS Timestamp: 2017-10-04 16:17:18; Journal ID: ISSN 0920-4105
Publisher:
Elsevier
Country of Publication:
Netherlands
Language:
English

Citation Formats

Ling, Kegang, He, Jun, Pei, Peng, Ge, Jun, and Qin, Wenting. A new correlation to evaluate the fracture permeability changes as reservoir is depleted. Netherlands: N. p., 2016. Web. doi:10.1016/j.petrol.2016.05.030.
Ling, Kegang, He, Jun, Pei, Peng, Ge, Jun, & Qin, Wenting. A new correlation to evaluate the fracture permeability changes as reservoir is depleted. Netherlands. doi:10.1016/j.petrol.2016.05.030.
Ling, Kegang, He, Jun, Pei, Peng, Ge, Jun, and Qin, Wenting. 2016. "A new correlation to evaluate the fracture permeability changes as reservoir is depleted". Netherlands. doi:10.1016/j.petrol.2016.05.030.
@article{osti_1359735,
title = {A new correlation to evaluate the fracture permeability changes as reservoir is depleted},
author = {Ling, Kegang and He, Jun and Pei, Peng and Ge, Jun and Qin, Wenting},
abstractNote = {},
doi = {10.1016/j.petrol.2016.05.030},
journal = {Journal of Petroleum Science and Engineering},
number = C,
volume = 145,
place = {Netherlands},
year = 2016,
month = 9
}

Journal Article:
Free Publicly Available Full Text
Publisher's Version of Record at 10.1016/j.petrol.2016.05.030

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  • The development of a strategy for the detailed three-dimensional (3D) description of permeability was a key ingredient of the recent reservoir characterization study of the Ekofisk field. Because the ultimate objective of this characterization effort was the construction of a new full-field 3D reservoir flow model, permeability and its heterogeneity received special focus. Permeability has a tremendous influence on history matching of reservoir fluid flow models and, in turn, reservoir-management decisions. This is particularly true in a mature, waterflooded field such as Ekofisk. The Ekofisk field is a high-porosity, low-matrix permeability naturally fractured chalk. Fluid-flow characteristics of the reservoir aremore » largely governed by the distribution, orientation, and interconnectivity of the natural-fracture system. To honor this mechanism, an algorithm was developed based on the log linear relationship between fracture spacing (intensity) data from core and well-test effective permeability. To capture the intrinsic heterogeneity and complex nature of Ekofisk field, the basic relationship between fracture intensity and permeability was modified to incorporate variations associated with (1) chalk facies; (2) fracture type; (3) porosity; (4) structural location; (5) structural curvature; and (6) silica content. To calibrate the algorithm, permeability determined from distributing total well-test flow capacity (kh) based on production log contribution was used as a tuning parameter. As a final step, geostatistical techniques were used to ensure that permeabilities derived from the algorithm matched those obtained from well-test analysis.« less
  • Sixty-five percent of the reserves of the Kuparuk River field, the second-largest producing oil field in the U.S., is contained in a 20- 80-md-permeability sandstone. This paper provides details of stimulation design advances made over the past 3 years in this formation. The design steps for optimizing fracture treatments in a moderate-permeability formation require primary emphasis on fracture conductivity rather than on treatment size or fracture length. This philosophy was used for the 140 new wells documented in this paper. Treatment size was gradually increased once a commensurate increase in fracture conductivity was obtained. Applying the new design to themore » refracturing of 88 producing wells in the field resulted in an incremental 40,000 BOPD, a significant portion of the field's 300,000 BOPD.« less
  • Here, beneficial pore space and permeability enhancements are likely to occur as CO 2-charged fluids partially dissolve carbonate minerals in carbonate reservoir formations used for geologic CO 2 storage. The ability to forecast the extent and impact of changes in porosity and permeability will aid geologic CO 2 storage operations and lower uncertainty in estimates of long-term storage capacity. Our work is directed toward developing calibrated reactive transport models that more accurately capture the chemical impacts of CO 2-fluid-rock interactions and their effects on porosity and permeability by matching pressure, fluid chemistry, and dissolution features that developed as a resultmore » of reaction with CO 2-acidified brines at representative reservoir conditions. We present new results from experiments conducted on seven core samples from the Arbuckle Dolostone (near Wellington, Kansas, USA, recovered as part of the South-Central Kansas CO 2 Demonstration). Cores were obtained from both target reservoir and lower-permeability baffle zones, and together these samples span over 3–4 orders of magnitude of permeability according to downhole measurements. Core samples were nondestructively imaged by X-ray computed tomography and the resulting characterization data were mapped onto a continuum domain to further develop a reactive transport model for a range of mineral and physical heterogeneity. We combine these new results with those from previous experimental studies to more fully constrain the governing equations used in reactive transport models to better estimate the transition of enhanced oil recovery operations to long-term geology CO 2 storage. Calcite and dolomite kinetic rate constants (mol m –2 s –1) derived by fitting the results from core-flood experiments range from k calcite,25C = 10 –6.8 to 10 –4.6, and k dolomite,25C = 10 –7.5 to 10 –5.3. The power law-based porosity-permeability relationship is sensitive to the overall pore space heterogeneity of each core. Stable dissolution fronts observed in the more homogeneous dolostones could be accurately simulated using an exponential value of n = 3. Furthermore, unstable dissolution fronts consisting of preferential flowpaths could be simulated using an exponential value of n = 3 for heterogeneous dolostones, and larger values ( n = 6–8) for heterogeneous limestones.« less
  • Here, beneficial pore space and permeability enhancements are likely to occur as CO 2-charged fluids partially dissolve carbonate minerals in carbonate reservoir formations used for geologic CO 2 storage. The ability to forecast the extent and impact of changes in porosity and permeability will aid geologic CO 2 storage operations and lower uncertainty in estimates of long-term storage capacity. Our work is directed toward developing calibrated reactive transport models that more accurately capture the chemical impacts of CO 2-fluid-rock interactions and their effects on porosity and permeability by matching pressure, fluid chemistry, and dissolution features that developed as a resultmore » of reaction with CO 2-acidified brines at representative reservoir conditions. We present new results from experiments conducted on seven core samples from the Arbuckle Dolostone (near Wellington, Kansas, USA, recovered as part of the South-Central Kansas CO 2 Demonstration). Cores were obtained from both target reservoir and lower-permeability baffle zones, and together these samples span over 3–4 orders of magnitude of permeability according to downhole measurements. Core samples were nondestructively imaged by X-ray computed tomography and the resulting characterization data were mapped onto a continuum domain to further develop a reactive transport model for a range of mineral and physical heterogeneity. We combine these new results with those from previous experimental studies to more fully constrain the governing equations used in reactive transport models to better estimate the transition of enhanced oil recovery operations to long-term geology CO 2 storage. Calcite and dolomite kinetic rate constants (mol m –2 s –1) derived by fitting the results from core-flood experiments range from k calcite,25C = 10 –6.8 to 10 –4.6, and k dolomite,25C = 10 –7.5 to 10 –5.3. The power law-based porosity-permeability relationship is sensitive to the overall pore space heterogeneity of each core. Stable dissolution fronts observed in the more homogeneous dolostones could be accurately simulated using an exponential value of n = 3. Furthermore, unstable dissolution fronts consisting of preferential flowpaths could be simulated using an exponential value of n = 3 for heterogeneous dolostones, and larger values ( n = 6–8) for heterogeneous limestones.« less