Berlin, Jacob M. (Rice University) | Yu, Jie (Rice University) | Lu, Wei (Rice University) | Walsh, Erin E. (Rice University) | Zhang, Lunliang (Rice University) | Zhang, Ping (Rice University) | Chen, Wei (Nankai University) | Kan, Amy T. (Rice University) | Wong, Michael (Rice University) | Tomson, Mason B. (Rice University) | Tour, James M. (Rice University)
Polyvinyl alcohol functionalized oxidized carbon black efficiently carries a hydrophobic compound through a variety of oil-field rock types and releases the compound when the rock contains hydrocarbons.
The transport of small hydrophobic organic molecules through porous media has been studied for many years. In isolation, these hydrophobic molecules sorb very strongly to nearly all types of soil. However, it has been observed that these hydrophobic chemicals disperse more broadly in the environment than would be expected based on their strong affinity for binding to soil (Baker, 1986). One possible explanation for this behavior is that organic macromolecules, which possess amphiphilic characteristics, may sequester the hydrophobic small molecules and facilitate their transport by carrying them within the macromolecule (McCarthy, 1989; Enfield, 1988). Laboratory scale experiments have demonstrated this effect, with some cases, such as the use of ß-cyclodextrin, showing highly efficient transport of a variety of hydrophobic aromatic molecules through soil (Brussea, 1994; Magee, 1991). However, selective release of the transported cargo has not been reported and ß-cyclodextrin only forms 1:1 inclusion complexes with its hydrophobic cargo.
Carboxybetaine visco-elastic surfactants have been applied in acid diversion, matrix acidizing and fracturing treatments, in which high temperatures and low pH are usually involved. Amido-carboxybetaine surfactants are subject to hydrolysis under such conditions due to the existence of a peptide bond (-CO-NH-) in their molecules, leading to alteration of the rheological properties of the acid. The objective of this paper is to study the impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine visco-elastic surfactant-based acids, and determine the mechanism of viscosity alterations by molecular dynamics (MD) simulations.
Surfactant-acid solutions with different compositions (surfactant concentration varied from 4 to 8 wt%) were incubated at 190°F for 1 to 6 hours. Solutions were then partially spent by CaCO3 until the sample pH was 4.5, and the apparent viscosity was measured using a HT/HP viscometer. To determine the mechanism for viscosity alteration on molecular level, MD simulations were carried out on spent surfactant-acid aqueous systems using the Materials Studio 5.0 Package.
It was found that short time hydrolysis at high temperatures (for example, 1 to 2 hours at 190°F) led to a significant increase in surfactant-acid viscosity. However, after long time incubation, phase separation occurred and the acid lost its viscosity. Simulation results showed that the viscosity alteration of amido-carboxybetaine surfactant-acid by hydrolysis at high temperatures may be due to different micellar structures formed by carboxybetaine and fatty acid soap, its hydrolysis product. The optimum molar ratio of amido-carboxybetaine and fatty acid soap was found to be nearly 3:1 from our simulations.
Our results indicate that hydrolysis at high temperatures has great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel break-down can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.
Kaufman, R.L. (ChevronTexaco) | Dashti, H. (Kuwait Inst. for Scientific Research) | Kabir, C.S. (ChevronTexaco) | Pederson, J.M. (ChevronTexaco) | Moon, M.S. (ChevronTexaco) | Quttainah, R. (Kuwait Oil Co.) | Al-Wael, H. (Kuwait Oil Co.)
This study reports reservoir geochemistry findings on the Greater Burgan field by a multidisciplinary, multiorganizational team. The major objectives were to determine if unique oil fingerprints could be identified for the major producing reservoirs and if oil fingerprinting could be used to identify wells with mixed production because of wellbore mechanical problems. Three potential reservoir geochemistry applications in the Burgan field are: (1) evaluation of vertical and lateral hydrocarbon continuity, (2) identification of production problems caused by leaky tubing strings or leaks behind casing, and (3) allocation of production to individual zones in commingled wells. Results from this study show that while oils from the major reservoir units are different from each other, the differences are small. Furthermore, a number of wells were identified in which mixed oils were produced because of previous mechanical problems. Both transient pressure testing and distributed pressure measurements provided corroborative evidence of some of these findings. Other data show that Third Burgan oils are different in the Burgan and Magwa sectors, suggesting a lack of communication across the central graben fault complex. This finding supports the geologic model for the ongoing reservoir simulation studies. Success of the geochemistry project has spawned enlargement of the study in both size and scope.
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.
Comparison of petrophysical properties between Eastern U.S. Silurian-age sandstones and Western U.S. Cretaceous-age sandstones illustrates the universality of certain low-permeability reservoir properties. In the Medina insitu porosities are generally within 97% of routine porosities and in Mesaverde-Frontier are approximately 0.8 porosity percent less than routine porosities. In both groups insitu Klinkenberg permeability (ki) exhibits an increasing difference from routine air permeability with decreasing permeability. Both groups of low-permeability sandstones exhibit very similar decrease in "irreducible" water saturation (Siw) with increasing ki. However, lithologic variations that are related primarily to grain size and shaliness cause variance in Siw at any given permeability. Both eastern and western low-permeability sandstones exhibit sharp decrease in gas relative permeability ( krg,Siw) with increasing Siw. The krg,Siw values are generally less than 5% at Siw greater than 60%. Although average krg,Siw is low and average Siw is high, these sandstones typically produce water-free gas. Analysis of cumulative flow capacity in wells in both regions indicates that a significant fraction of total flow capacity often comes from a few, thin, higher permeability intervals within generally low-permeability sandstone. Although storage capacity declines with decreasing permeability due to increasing Siw, low-permeability intervals still represent a significant fraction of total storage.
Lower Silurian-age low-permeability Medina Group (Medina) sandstones of the Appalachian Basin and Upper Cretaceous-age Mesaverde Group (Mesaverde) and Frontier Formation (Frontier) sandstones in several Western U.S. basins are important targets for natural gas exploration and production. Recoverable reserves are estimated to be approximately 30 trillion cubic feet (TCF) in the Medina1 and approximately 10 TCF in the low-permeability Mesaverde and Frontier.2 The abundant gas reserves of the Medina, which drillers locally call the "Clinton," are regionally extensive and without a recognized downdip water contact. Mesaverde and Frontier reservoirs exhibit similar undefinable gas-water contacts. In both areas water can occur updip of gas production.
Prediction of gas producibility from low-permeability sandstones is complicated because conventional log-analysis interpretation and formation-evaluation parameters are commonly not applicable. Furthermore, conventional core-analysis petrophysical values can differ significantly from reservoir values. Early work on petrophysical properties of low-permeability sandstones demonstrated that pore-volume compressibility is small and that increasing confining stress and water saturation cause permeability to decrease.3,4,5 Jones and Owens6 quantified these effects and concluded that the presence of a thin, sheet-like, tabular pore structure could explain the response to confining stress. Ostensen7 provided a comprehensive theoretical analysis of the relationship between grain boundary micro-crack dimensions and permeability. Dutton et al.2 summarized the properties of low-permeability sandstones in the U.S. and provided extensive references to previous studies. Recently, Byrnes 8 summarized insitu rock properties for low-permeability sandstones in Rocky Mountain basins and Castle and Byrnes9 presented insitu rock properties for the Medina in northwestern Pennsylvania.
Ewing Bank 873 is an offshore Gulf of Mexico field discovered in 1991 in 775 ft of water. The discovery well was drilled on a seismic amplitude anomaly on the flank of a salt withdrawal mini-basin. Field development began in 1994, and in mid 1998 daily production from the Bulminella 1 reservoir averaged 40,000 BOPD and 32 x 106 ft3/D of gas. The Bul 1 reservoir in this combination structural-stratigraphic trap consists of six stacked and overlapping Pliocene turbidite sand lobes. In turn, integration of seismic, well log, geochemical and pressure data indicates these six turbidite lobes comprise three compartments. All of the various data types give constraints on different aspects of compartmentalization, but at the stratigraphically complex Ewing Bank 873 field, geochemical analyses provided key information unavailable through any other means. These geochemical analyses were performed as individual wells in the field went on production and immediately provided information regarding fluid communication and reservoir connectivity that was missing from earlier interpretations based solely on seismic and log data. Early recognition of three reservoir compartments using geochemical data also helped constrain preliminary stratigraphic interpretations and provided initial input for flow units and reservoir simulation models. The geochemical information further provided advance notice of economically significant oil quality variations in the three compartments. These fluid variabilities were later substantiated by PVT analyses and include notable differences in oil gravity, weight percent sulfur, viscosity and solution gas. Integrating all available data shows there are three compartments at EW 873 and each compartment comprises different turbidite sand lobes and exhibits its own characteristic pressure regime and fluid properties. The early indications of both compartmentalization and variation in fluid properties by the geochemical analyses contributed significantly to improved field recovery and economics by allowing fewer and better placed wells to be drilled.