Saudi Arabian Oil Company

Jinxun Wang

Ming Han

Abdulkareem M Al-Sofi

Xuan Zhang

Abdulkareem AlSofi

Subhash Chandrabose Ayirala

Ali Abdallah Al-Yousef

Amar Jaber M Alshehri

Dongqing Cao

Hassan W Al Hashim

Amar J Alshehri

Ying Wang

Jun Gao

Abdulkareem M Alsofi

Saleh F Hassan

Jian Hou

Abdulaziz AlKhateeb

Abdullah Al-Boqmi

A removable apparatus having a core holder body and a core sample assembly fitted inside the core holder body is disclosed. The core sample assembly includes a core sample and a sleeve fitted around the core sample. A first flanged stopper and a second flanged stopper are positioned at opposite axial ends of the core holder body. A flow path is formed through the first and second flanged stoppers and interfaces at opposite end surfaces of the core sample. Also provided are an assembly and a system comprising the removable apparatus for use in oilfield applications. Further, a method of testing a property of a fluid using the removable apparatus is provided.

On-line core holder design for polymer quality testing device

A core sample holder for testing core samples from a well includes a body having a wall defining a cavity. At least two sleeves are disposed within the cavity parallel to each other. Each sleeve of the at least two sleeves is configured to individually hold the core samples. At least one cap is removably coupled to an inner surface of the wall. A tube extends from each end of the at least two sleeves to be a dedicated inlet at a first end of each sleeve and a dedicated outlet at a second end of each sleeve.

Methods and systems for a parallel flow core sample holder

A method includes acquiring a core sample from a first reservoir of interest that is producing hydrocarbons at a first recovery rate. The method includes performing a coreflooding study using a core flood apparatus. The coreflooding study includes a plurality of coreflooding simulations using the core sample disposed in the core flood apparatus. The method includes performing a reservoir simulation study on the first reservoir using a coreflooding simulation model and using the coreflooding study. The method includes adjusting a core flood fluid based on the reservoir simulation study to form an adjusted treatment fluid that produces a second recovery rate from the first reservoir. The second recovery rate may be greater than the first recovery rate. The method includes using an injection well and the adjusted treatment fluid for performing an injection operation of a reservoir.

Compact apparatus for quick core flood tests and method of use

Compositions that include cationic surfactants and methods of synthesizing compositions that include cationic surfactants. The surfactants include a quaternary amine and a saturated or unsaturated alkyl chain with 4 to 28 carbons. The surfactants can be generated by reacting a fatty acid modified with an amino alkyl group and an epihalohydrin in the presence of a base. The cationic surfactants can be generated by reacting a fatty acid modified with an amino alkyl group, an epihalohydrin, and a carboxylic acid. The cationic surfactants can be generated by reacting a carboxylic acid, an epihalohydrin, and a catalyst to afford a halo-substituted alkyl ester, followed by reacting the halo-substituted alky ester with a fatty acid modified with an amino alkyl group.

Preparation of cationic surfactants

The systems and method described in this specification relate to at least partially restoring porosity and brine permeability of carbonate core samples. The systems and methods include extracting a carbonate core sample from a subterranean formation. The extracted carbonate core sample is inserted into a core flooding test machine. A first porosity and a first brine permeability of the extracted carbonate core sample is measured. A fluid is pumped through the extracted carbonate core sample to flood the carbonate core sample. The fluid includes at least one of a high-molecular weight polymer solution and a gel particle solution. The systems and methods include at least partially restoring the porosity and the brine permeability of the carbonate core sample by pumping an oxidizing solution through the flooded carbonate core sample and heating the carbonate core sample to a temperature of at least 60° C. after pumping the oxidizing solution through the carbonate core sample.

Restoring core samples

A method includes saturating a core sample with a hydrocarbon fluid to provide a hydrocarbon-saturated core, placing the core into a first aqueous fluid, applying an external force at increasing magnitude to the hydrocarbon-saturated core to displace a volume of the hydrocarbon fluid in the hydrocarbon-saturated core with the first aqueous fluid at each pressure magnitude, measuring a volume of displaced hydrocarbon fluid at each pressure magnitude, obtaining a first capillary pressure curve, re-saturating the core sample, placing the hydrocarbon-saturated core into a second aqueous fluid having a wettability altering agent, applying an external force at increasing magnitude to displace a volume of the hydrocarbon fluid in the core with the second aqueous fluid at each pressure magnitude, measuring a volume of displaced hydrocarbon fluid at each pressure magnitude, obtaining a second capillary pressure curve, and calculating a contact angle of the second aqueous fluid.

Centrifuge method for evaluating contact angle and wettability alteration

Copolymer compositions and methods of making copolymer compositions with enhanced stability in high temperature and high salinity environments. The copolymers include hydrophobic monomers and sulfonated monomers. The sulfonated monomers can include 2-acrylamido-2-methylpropane sulfonic acid and allyl sulfonate. The sulfonated monomers increase the stability of the polymers in harsh conditions, and in high temperature, high salinity environments. The sulfonated monomers also reduce or prevent the hydrolysis of acrylamide groups, and therefore enhance the stability of the copolymer. The copolymer compositions can be made with free radical polymerization and an initiation complex.

Sulfonated polymer

A surfactant composition is provided. The composition includes chemical structure represented by Formula (1): where Rrepresents a hydrocarbon group, a substituted hydrocarbon group, an alkyl ester group, or an alkyl amine having from 4 to 28 carbon atoms, and Rand Rrepresent hydrocarbon groups having from 1 to 5 carbon atoms. Also provided is a composition including a brine comprising a total salinity of at least 20,000 mg/L and the chemical structure shown in Formula (1). Methods of making a composition including the chemical structure represented by Formula (1) are also provided.

Composition and method of making cationic surfactants with two quaternary ammonium head groups

A method of determining foam stability includes placing a core plug and two porous plates into a core holder of a vesselcore plug. The first porous plate and the second porous plate are disposed on opposite sides of the core plug, and the core plug, the first porous plate, and the second porous plate are saturated with surfactant. The method further includes alternating surfactant solution injections between a first injection area located on the first porous plate and a second injection area located on the second porous plate, while ensuring that the surfactant solution is being continuously fed, thereby forming continuously flowing foam in-situ within the core plug, in which the surfactant solution comprises gas and the surfactant; and monitoring the pressure drop to determine the stability of the foam in the core plug.

Method for determining foam stability in a core plug

A method for retrieving heavy oil from a reservoir by injection of solvent, hot water, and polymer solution. This method includes the steps of providing an injection well traversing into reservoir containing heavy oil. Sequential injections of solvent, a hot water and polymer solution are performed via the injection well traversing into reservoir containing the heavy oil. The solvent, hot water, and polymer solution intermingle with the heavy oil within the reservoir to form a heavy oil mixture that is retrieved from a production well. The sequential solvent and hot water injection may also be repeated to reduce the viscosity of the heavy oil until an estimated viscosity of the heavy oil in the reservoir is below a threshold viscosity before injecting polymer solution into the reservoir.

Sequential injection of solvent, hot water, and polymer for improving heavy oil recovery

A method of evaluating gel stability of a gel for treating a subterranean formation includes placing a composite core plug into a core holder of a coreflood testing device where the composite core plug comprises first, second, and third core plugs, alternating injection of polymer solution into first and second injection areas, and monitoring a pressure drop across the composite core plug as a function of time. The method further includes identifying a gelation of a gelent solution in the third core plug, where the gelation is indicated by an increase in the pressure drop across the composite core plug, after the increase in the pressure drop indicative of the gelation point, continuing alternating injections of the polymer solution into the first and second injection areas, and identifying a reduction in the pressure drop across the composite core plug indicative of deterioration of the gel.

Evaluating gel stability by injection in alternating flow directions

Techniques for analyzing a sample include preparing a sample; circulating a gel solution through the sample to saturate the sample; scanning the saturated sample with a nuclear magnetic resonance (NMR) system to determine two or more NMR values of the saturated sample; determining a permeability of the saturated sample based, at least in part, on the two or more NMR values of the saturated sample; aging the saturated sample; scanning the aged sample with the NMR system to determine two or more NMR values of the aged sample; determining a permeability of the aged sample based, at least in part, on the two or more NMR values of the aged sample; comparing the determined permeability of the saturated sample against the determined permeability of the aged sample; and based on the compared permeabilities, determining a gel solution syneresis rate.

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Dhahran, Saudi Arabia

Jinxun Wang