Giant Gas-condensate Field Research Articles

Integrated Study Aids Characterization and Modeling of Natural-Fracture Networks

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186043, “An Integrated Study To Characterize and Model Natural-Fracture Networks of Gas-Condensate Carbonate Reservoirs, Onshore Abu Dhabi,” by Budour Ateeq, Mohamed El Gohary, Khalid Al Ammari, and Rashad Masoud, ADCO; Abdelwahab Noufal, ADNOC; Ghislain de Joussineau and Martin Weber, Beicip Franlab; and Dinesh Agrawal, IFP Middle East Consulting, prepared for the 2017 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, 8–10 May. The paper has not been peer reviewed. Natural fractures can have a significant effect on fluid flow by creating permeability anisotropy in hydrocarbon reservoirs. They can also play an undesirable role in reservoir subsidence and compaction during depletion, with important consequences for production strategy. The investigation of these effects motivated a comprehensive integrated fracture study of three reservoirs from a giant gas-condensate field in Abu Dhabi. The main objective was to build 3D fracture models and compute fracture properties of each reservoir, to be used in dynamic simulations. Introduction The studied reservoirs are gas-condensate-bearing in a carbonate field onshore Abu Dhabi. The field has an anticlinal structure and consists of a series of stacked reservoirs, among which three (Reservoirs A, B, and C) were part of this study. For each reservoir, the production comes mainly from the large gas-bearing area above the gas/oil contact, which is surrounded by a thin peripheric oil rim. The studied field has a long production history; Reservoir A has produced oil and gas for 30 years. Minor fracturing was observed during routine core analyses in the past, but a comprehensive fracture characterization at field scale was never conducted. Because fractures may have a major bearing on production and could play a significant role in rock compaction and collapse during reservoir depletion, an important objective was to ascertain the risk related to the geomechanical stability of these reservoirs because of the presence of natural-fracture networks. Work Flow An integrated work flow was applied in order to characterize fracture distribution and flow effect in the reservoirs properly. The work flow consisted of the following key steps: Fracture characterization from 3D seismic data and subsequent detection of fracture corridors Fracture characterization from core data Fracture characterization from borehole image data Fracture characterization from well dynamic data Conceptual fracture model Building of a 3D fracture model Dynamic calibration of the 3D model using flowmeter and well-test data Upscaling and computation of equivalent fracture properties for the simulation grid using the calibrated model Static Fracture Characterization Fracture characterization using the seismic data initiated the work flow and was followed by the interpretation of fractures from borehole images and core data. Fracture Characterization From 3D Seismic Data. This task was performed to detect the seismic and the subseismic faults and fracture corridors within the three reservoirs. Seismic fracture-facies maps and fracture-index maps were created on the basis of post-stack discontinuity attributes (e.g., curvature, polar dip, and similarity) computed from the inverted seismic cube.

Gas-condensate production improvement using wettability alteration: A giant gas condensate field case study

Productivity loss due to condensate blockage is the main and common problem in gas condensate reservoirs around the world. Several methods such as gas recycling, hydraulic fracturing and solvent injection have been proposed to overcome this problem. But these methods usually are effective just for short periods of time. A novel approach in gas condensate reservoirs is altering the wettability of the reservoir rocks from strongly liquid wetness to preferential gas wetness or intermediate-wetting by treating them with chemicals. Most of experimental studies have focused on finding chemicals to perform a permanent wettability alteration in lab scale, but the effect of wettability alteration on production improvement in field scale has not been studied well enough, yet.In this paper, the effect of wettability alteration on gas-condensate production improvement in field application was studied. First a radial single compositional well model was constructed using fluid and reservoir data from a giant gas condensate field in the Middle East located in the south of Iran. Three different relative permeability curves have been used in the model which represent three different wettability states.The results showed that field gas-condensate cumulative production was improved greatly after the wettability of porous media was altered from liquid-wetting to intermediate- or gas-wetting by changing relative permeabilities for a treatment radius of 5 m around the wellbore. Production improvement in the intermediate-wetting state was maximized. Also, wettability alteration results in decreasing condensate saturation around the well and increasing the well bottomhole flowing pressure and productivity index.

Occurrence of Oil and Gas Fields and Source Rock Transformation in the West Siberian Basin and Barents Sea Platform

The West Siberian and Barents Sea basins contain the largest demonstrated reserves of gas in the world (more than 33 trilion m[sup 3]) and very large recoverable reserves of oil (about 19 billion tons). The main productive reservoirs are of the Jurassic and Cretaceous and are composed of marine and alluvial sandstones. Major gas fields of the West Siberian basin are located north of the Arctic Circle, from which they extend into the Yamal Peninsula and offshore into the Kara Sea. Oil fields of the basin are found mainly in the middle Ob region. Only one giant gas-condensate field has been found in the Barents Sea; however, this area has excellent potential for gas-condensate discoveries in the future. Both basins contain Kimmeridgian-Tithonian black-shale formations, which are prolific oil source rocks. In the Barents Sea basin, Kimmeridgian black shales contain 7 to 9% of organic carbon; total pyrolysis yield ranges from 5.3 to 84.2 mg HC/g rock, and hydrogen index ranges from 270 to 630 mg HC/g TOC. Our pyrolysis data and basin modeling (GALO version) indicate that the realization of the initial petroleum potential in the Shtokmanov field area has not begun because the volume of generated oil (about 8more » mg HC/g TOC) is insufficient to start expulsion (threshold of expulsion is equal to 96 mg HC/g TOC). The Bazhenov Formation shales in the central part of the West Siberian basin are characterized by extremely high values of pyrolysis measurements. The organic carbon content ranges from 10 to 25%; the residual petroleum potential varies from 50 to 190 mg HC/g rock; the maturity typically corresponds to the oil window zone; and the amount of expelled hydrocarbons ranges from 40 to 60 mg HC/g rock. The expulsion of oil commenced 90 to 35 m.y. In the northern part of the West Siberian basin, the Bazhenov shales are lean source rocks.« less

Arun Field: a Giant Gas-Condensate Field Producing from Miocene Reef Facies, North Sumatra Basin, Indonesia: ABSTRACT

Arun Field: a Giant Gas-Condensate Field Producing from Miocene Reef Facies, North Sumatra Basin, Indonesia: ABSTRACT