Investigation of H2S Migration in the Marjan Complex
- Mohammad I. Al-Eid (Saudi Aramco) | Sunil L. Kokal (Saudi Aramco) | William J. Carrigan (Saudi Aramco) | Jaffar M. Al-Dubaisi (Saudi Aramco) | Henry I. Halpern (Saudi Aramco) | Jamal I. Al-Juraid (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- December 2001
- Document Type
- Journal Paper
- 509 - 515
- 2001. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.1.1 Exploration, Development, Structural Geology, 1.8 Formation Damage, 4.1.9 Heavy Oil Upgrading, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 4.6 Natural Gas, 5.5 Reservoir Simulation, 1.14 Casing and Cementing, 5.1.2 Faults and Fracture Characterisation, 5.2.3 Geochemical Characterization, 4.3.3 Aspaltenes, 4.3.4 Scale, 5.2.2 Fluid Modeling, Equations of State
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The Marjan complex is a large offshore oil field located in the Arabian Gulf and composed of four fields: Marjan 1, Marjan 2, Marjan 3, and Marjan 4. Currently, production in the complex is limited to the Khafji reservoir. For several years, it was known that the H2S concentration in the Khafji reservoir varied across the complex. A comprehensive study was initiated to map the concentration profile of H2S across the complex and to address the migration of H2S within it. This study included area-wide wellstream H2S measurement and geochemical fingerprinting of Marjan oil and gas. For the first time, the concentrations of H2S were mapped across the complex. The southern and southwestern wells show relatively high concentrations of H2S, and the northern wells show no (or negligible) amounts of H2S (less than 10 ppm). The migration of H2S into the northern part of the field has serious implications because the crude-handling facilities, or the gas/oil separation plant (GOSP), were designed for sweet crude processing. If migration is proven, the facilities in the northern part of the field must be upgraded to handle sour crude.
The results of this study indicate that there is a hot spot of high H2S located in the southwestern part of the complex. There is a significant H2S gradient across the Marjan complex, with H2S decreasing from the southwest to the northeast. H2S concentration profiles also indicate that there is an increase in H2S concentration with time in the hot spot. The data negate the possibility of H2S generation in the Khafji reservoir from either sulfate-reducing bacteria (SRB) or thermochemical sulfate reduction (TSR). Therefore, it is suggested that the H2S is migrating into the Khafji reservoir from somewhere else, probably from the Ratawi or other, deeper reservoirs.
The geochemical analyses show that the hydrocarbon composition is uniform across the complex, and there is no evidence for barriers to fluid flow within the Khafji reservoir. It is proposed that the lateral migration of H2S within the reservoir is arrested because of the presence of H2S-scavenging iron minerals. Two hypotheses are proposed for the migration of H2S into the Khafji reservoir from the Ratawi reservoir: (a) through interreservoir faults, or (b) through channeling leaks behind well casings. These two hypotheses are discussed in the paper.
The Marjan complex consists of the main Marjan 1 field and the adjoining fields of Marjan 2, Marjan 3, and Marjan 4. Currently, production in the area is limited to the Khafji reservoir, a thick middle Cretaceous sandstone reservoir. There are three GOSPs in the complex processing Arab Medium crude. The northern part of the Marjan complex is sweet, and the southern part is sour. Marjan GOSP-A, located in the northern part of the Marjan complex, was designed for sweet crude. The central and southern GOSPs process sour crude. The concentration of H2S varies in the Marjan complex, with the southern wells showing relatively high concentrations of H2S and the northern wells (GOSP-A) showing no (or negligible) amounts of H2S. There was a concern that H2S may be migrating from south to north.
A preliminary reservoir simulation study was conducted to address the issue of H2S migration in Marjan. The study concluded that sour crude was migrating into the northern part of the complex before 1992, when GOSP-A wells were on production. In 1993, GOSPs B and C came on stream, and the migration rate was reduced considerably.
The present study was initiated to investigate the migration of H2S in the Marjan complex. The main objective of the study is to determine the source and migration pathways of H2S into the Khafji reservoir. The research study was split into two parts: (a) a pressure/volume/temperature (PVT) and phase behavior study to address the variation of H2S across the complex, and (b) a geochemical study to determine the origin of the H2S and the extent of fluid communication within the reservoir. Specific objectives and tasks include:
Obtain new fluid-composition data and compare them with previous H2S data to ascertain if H2S concentrations have changed with time (and if so, to what extent) across the complex.
Map the variation in H2S concentrations across the complex.
Determine whether there is H2S migration in the complex and determine the most probable mechanism causing this migration.
Determine whether any reservoir compartments exist. Such compartments may either protect sweet crude from H2S migration or provide a trapping mechanism for sour crude pockets.
Determine the origin of H2S through sulfur isotope analysis.
Compare oils obtained in the early 1980s with oils from the same wells obtained currently to identify possible production-related migration.
Provide input data for a reservoir simulation model with H2S tracking capability.
H2S Measurement and Mapping
The objective of fluid sampling is to collect representative oil and gas samples. This is a critical operation because all the laboratory measurements depend on the success of the sampling program. Pressurized oil and gas samples were used for analysis and sulfur isotopes of H2S. Depressurized oil samples were used for geochemical characterization. A fieldwide wellhead gas-sampling program was also undertaken to determine the concentration of H2S in the wellhead samples.
In this program, gas samples were collected from the wellhead, and H2S concentrations were measured at the wellsite. All wellhead gas samples were collected from sampling points located downstream of the wellhead chokes (Fig. 1). More than 120 wells were sampled and analyzed.
H2S Measuring Methodology.
Analyzing H2S in the reservoir fluid or wellstream is an elaborate task. All measurements reported in this study were made on the gas stream and then converted to reservoir fluid concentration with a PVT simulator (described later). For a given reservoir fluid composition, the concentration of H2S in the gas stream is a function of its pressure and temperature.
Wellhead Gas Samples.
Different methods are used to measure the concentration of H2S in gas mixtures. The method needed for measuring depends on the H2S concentration in the sampled fluid. The Tutwiler method1 is used at high concentrations (>1,000 ppm), the length-of-stain detector tube method2 (Drager and Gastec) is used over a wide range from very low (1 ppm range) to high concentrations (up to 40%), and the Gas Monitor3 is used at low concentrations (<1,000 ppm). The Tutwiler method is generally considered more accurate at high concentration levels (>5,000 ppm).
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