Application of Petrophysically Derived "Flow Facies" for Reservoir Characterization and Simulation: Wara Reservoir, Greater Burgan Field

Moon, M.S.; Pederson, John M.; Osmon, Kamal; Al-Saied, Mariam; Al-Sabea, Salem; Al-Shammari, Hana'a

doi:10.2118/49217-ms

Cited by 11 publications

(2 citation statements)

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“…Holtz and Hamilton (1996) proposed that flow units have interdependent petrophysical parameters over distance, and it is feasible to predict the flow units for uncored wells. Various methods such as rank correlations on wireline logs (Abbaszadeh et al 1996); saturation and depth profiles (Martin et al 1997); and the stochastic modeling of shale fraction and effective porosity (Moon et al 1998) are used for that purpose. Davies and Vessell (1996) developed an algorithm from which rock types are predicted from wireline logs.…”

Section: Literaturementioning

confidence: 99%

A New Approach in Permeability and Hydraulic-Flow-Unit Determination

Izadi

Ghalambor

2013

SPE Reservoir Evaluation &Amp; Engineering

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Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field-development plans. All field-data acquisitions from seismic, well logging, production, and geomechanical monitoring to enhanced-oil-recovery (EOR) operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model of the field and associated operations is essential for a successful implementation of such projects. Furthermore, using a more reliable model can, in turn, provide the basis in the decision-making process for control and remediation of formation damage.One of the key identifiers of the subsurface model is accurately predicting the hydraulic-flow units (HFUs). There are several models currently used in the prediction of these units on the basis of the type of data available. The predictions that used these models differ significantly because of the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions, thus increasing the need for better models.A new approach has been developed in this study for predicting the petrophysical properties and improving the reservoir characterization. The Poiseuille flow equation and Darcy equation were coupled, taking into consideration the irreducible water saturation in the pore network. The porous medium was introduced as a domain containing a bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis was performed on 17 Berea sandstone samples, and the petrophysical properties were measured and X-ray diffraction (XRD) analysis was conducted.In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers, each layer representing one Berea sample. Afterward, by the iteration and calibration of the laboratory data, the number of HFUs was determined by use of the common HFU model and the proposed model accordingly.A comparative study shows that the new model provides a better distribution of HFUs and prediction of the petrophysical properties. The new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for the Berea sandstone experimental data and the model predictions by use of the new permeability model shows a wider range of applicability for various reservoir conditions. In addition, the model has been applied to a series of core-analysis data on lowpermeability Medina sandstone, Appalachian basin, northwest Pennsylvania. The flow-unit distribution by use of the proposed model shows a better flow-zone distinction, and the permeability/ porosity relationship has a higher confidence coefficient.

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Section: Literaturementioning

confidence: 99%

A New Approach in Permeability and Hydraulic-Flow-Unit Determination

Izadi

Ghalambor

2013

SPE Reservoir Evaluation &Amp; Engineering

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“…The Wara formation 1 does not have a massive sand accumulation characteristic, and sand-shale interbedding is a norm. Sand intervals seldom exceed ten feet, therefore spherical flow periods were never observed in past conventional buildup tests.…”

Section: Introductionmentioning

confidence: 99%

Lessons learned from Wireline Formation Testing with Single and Multiple Probes

Su¹,

Al-Anezi²,

Sinha³

et al. 2001

Proceedings of SPE Middle East Oil Show

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPreviously there were few RFT data available for the Wara formation of the Greater Burgan field. Therefore, during recent drilling, pressure measurements were made to investigate if vertical pressure equilibrium exists in the formation after a production history of more than fifty years. The erratic nature of measured pressure profiles indicates that vertical communication is poor in the reservoir.In each of the pressure measurements, a single probe was inserted into the mud filtrate zone, and then about 20 cc of liquid was collected. In addition to obtaining the pressure value, we also derived the permeability value by diagnosing the pressure derivative signatures. Multiple probes were also used to evaluate vertical permeability over an interval of 2.3 feet. This paper describes how we analyze the data and overcome the problems encountered. We demonstrate that 3D-reservoir simulation of the formation test can improve the quality of data interpretation. A summary of the analytical method development is also given.Due to the high precision, 0.01 psi, of the quartz gauge, the single-probe pressure derivative data quality was satisfactory for low permeability sands and the analytical method could derive both the horizontal and vertical permeability values successfully. However, for high permeability sands, there often existed a pressure hump immediately after shut-in and it resulted in unrecognizable signatures.A non-linear regression method was used to interpret multiple-probe test data. However, sometimes a simultaneous pressure match for all the probes was difficult to achieve by the analytical model. 3D finite-difference simulation was required to fit the data and characterize the geological heterogeneity. Single-probe pre-test results were used to provide a good initial permeability guess for the numerical model. Gamma ray and formation image loggings were proven valuable to determine the layering of the numerical model. Finally, core measurement and buildip test results were compared with formation test results.

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