King Fahd University of Petroleum and Minerals

Saudi Arabian Oil Company

Ammar El-Husseiny

Mohamed Mahmoud

Mahmoud Elsayed

Karem Al-Garadi

Hyung Tae Kwak

Muhammad Shahzad Kamal

Murtada Saleh Aljawad

Panagiotis Kirmizakis

Panteleimon Soupios

Ali Abdulwahab Oshaish

Ahmed Binghanim

A method to measure acid diversion efficiency in rock samples. The method includes measuring a first porosity and a permeability of the rock samples. The method includes flooding a core region of the rock sample with a hydrochloric acid (HCl) system to create a wormhole, wherein during the flooding the HCl system penetrates from a first end of the rock sample to a second end of the rock sample to form the wormhole. The method includes measuring a second porosity, a pore size distribution, and a diffusion tortuosity of the rock samples with NMR. The method includes establishing a diversion index (DI) based off a ratio between the diffusion tortuosity in a first direction and the diffusion tortuosity in a second direction. The method includes determining the acid diversion efficiency based off the diversion index.

Method to measure acid diversion efficiency in matrix acidizing through NMR

A method of emulsion detection includes executing an oil production process from a volume of a formation. While executing the oil production process, conducting real-time spectral induced polarization (SIP) measurements of the volume of the formation to determine a real-time real conductivity value (RCV) of a matrix material in the volume of the formation. The method further includes determining an onset of water-in-oil (W/O) emulsion formation in the volume of the formation by analyzing the real-time RCV of the matrix material and optionally identifying the onset of the W/O emulsion formation when the real-time RCV first exceeds a first threshold value.

Detection of water in oil emulsions using spectral induced polarization

A method for predicting formation permeability by measuring diffusional tortuosity in several directions by pulse gradient NMR. The method comprises evaluating an anisotropic diffusion coefficient by pulsed gradient NMR, determining diffusional tortuosity from the restricted diffusion data, supplementing the NMR results with resistivity and sonic logging data, measuring anisotropic tortuosity and porosity by resistivity and sonic data and combining all components in a single fitting model. The 11-coefficient model is trained to recognize the true values of permeability by comparing the real oil permeabilities measured. in a library of oil-carrying rock cores with the NMR, resistivity and sonic correlates The fitting coefficients are extracted by minimizing the discrepancy between the laboratory measured permeabilities and the predicted values combining all rapid logging information components with the agreement-maximizing weights.

Method for downhole determination of permeability anisotropy using NMR

A method for predicting formation permeability by measuring diffusional tortuosity in several directions by pulse gradient NMR. The method comprises evaluating an anisotropic diffusion coefficient by pulsed gradient NMR, determining diffusional tortuosity from the restricted diffusion data, supplementing the NMR results with resistivity and sonic logging data, measuring anisotropic tortuosity and porosity by resistivity and sonic data and combining all components in a single fitting model. The 11-coefficient model is trained to recognize the true values of permeability by comparing the real oil permeabilities measured in a library of oil-carrying rock cores with the NMR, resistivity and sonic correlates. The fitting coefficients are extracted by minimizing the discrepancy between the laboratory measured permeabilities and the predicted values combining all rapid logging information components with the agreement-maximizing weights.

Downhole method for determining geologic permeability

Method for determining permeability in a hydrocarbon formation

NMR method for determining permeability in geologic formation

Measurement method for determining resistivity and permeability in a borehole

A fracture geometry mapping method includes determining a value of a diffusive tortuosity in a first direction in a first rock sample from a subterranean formation with one or more hardware processors; determining a value of a diffusive tortuosity in a second direction in the first rock sample from the subterranean formation with the one or more hardware processors, the second direction orthogonal to the first direction in the first rock sample; determining a value of a diffusive tortuosity in third direction in the first rock sample from the subterranean formation with the one or more hardware processors, the third direction orthogonal to both the first direction and the second direction in the first rock sample; comparing the values of the diffusive tortuosities in the in the first direction, the second direction, and the third direction; and based on the comparison, generating a first fracture network map of the subterranean formation, the first fracture network map including a first plurality of anisotropic fracture pathways.

Mapping a fracture geometry

A method for assessing an optimal acid injection rate in the process of hydrocarbon formation stimulation. The method comprises evaluating an anisotropic diffusion coefficient by pulsed gradient NMR, introduction of a semi-empirical correction based on comparison of the downhole conditions with the library of laboratory experiments where such corrections were measured, extrapolation of the library data to the real downhole conditions. The improved values of the diffusion coefficients are applied in determining wormhole regime conditions that are optimal in terms of acid consumption per a unit of stimulated yield of the hydrocarbon.

Method for acid fracturing and acid stimulation based on NMR diffusion measurements

Method for evaluation of permeability anisotropy using NMR diffusion measurements for oil and gas wells

A method for rapid wettability evaluation during exploratory drilling of a hydrocarbon. The method include pre-saturation of the sample by a brine, measuring the bulk brine's TNMR relaxation parameter, expelling the brine by oil in the sample, measuring the oil's bulk and pore TNMR relaxation parameter, measuring the brine's non-reducible content and TNMR relaxation parameter of water in the presence of dominant oil content, expelling the oil by the brine and measuring the TNMR relaxation parameter of the irreducible oil content in the dominant brine. The measurements are combined in the index:=[()/]&#x2212;[()/],

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Dhahran, Saudi Arabia

Ammar El-Husseiny