Tar mats at the oil-water contact (OWC tar mats) in oilfield reservoirs can have enormous, pernicious effects on production due to possibly preventing of any natural water drive and precluding any effectiveness of water injectors into aquifers. In spite of this potentially huge impact, tar mat formation is only now being resolved and integrated within advanced asphaltene science. Herein, we describe a very different type of tar mat which we refer to as a "rapid-destabilization tar mat??; it is the asphaltenes that undergo rapid destabilization. To our knowledge, this is the first paper to describe such rapid-destabilization tar mats at least in this context. Rapid-destabilization tar mats can be formed at the crest of the reservoir, generally not at the OWC and can introduce their own set of problems in production. Most importantly, rapid-destabilization tar mats can be porous and permeable, unlike the OWC tar mats. The rapid-destabilization tar mat can undergo plastic flow under standard production conditions rather unlike the OWC tar mat. As its name implies, the rapid-destabilization tar mat can form in very young reservoirs in which thermodynamic disequilibrium in the oil column prevails, while the OWC tar mats generally take longer (geologic) time to form and are often associated with thermodynamically equilibrated oil columns. Here, we describe extensive data sets on rapid-destabilization tar mats in two adjacent reservoirs. The surprising properties of these rapid-destabilization tar mats are redundantly confirmed in many different ways. All components of the processes forming rapid-destabilization tar mats are shown to be consistent with powerful new developments in asphaltene science, specifically with the development of the first equation of state for asphaltene gradients, the Flory-Huggins-Zuo Equation, which has been enabled by the resolution of asphaltene nanostructures in crude oil codified in the Yen-Mullins Model. Rapid-destabilization tar mats represent one extreme while the OWC tar mats represent the polar opposite extreme. In the future, occurrences of tar in reservoirs can be better understood within the context of these two end members tar mats. In addition, two reservoirs in the same minibasin show the same behavior. This important observation allows fluid analysis in wells in one reservoir to indicate likely issues in other reservoirs in the same basin.
A Jurassic oil field in Saudi Arabia is characterized by black oil in the crest, with heavy oil underneath and all underlain by a tar mat at the oil-water contact (OWC). The viscosities in the black oil section of the column are similar throughout the field and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large, continuous increase in asphaltene content with increasing depth extending to the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. A simple new formalism, the Flory-Huggins-Zuo (FHZ) Equation of State (EoS) incorporating the Yen-Mullins model of asphaltene nanoscience, is shown to account for the asphaltene content variation in the mobile heavy oil section. Detailed analysis of the tar mat shows significant nonmonotonic content of asphaltenes with depth, differing from that of the heavy oil. While the general concept of asphaltene gravitational accumulation to form the tar mat does apply, other complexities preclude simple monotonic behavior. Indeed, within small vertical distances (5 ft) the asphaltene content can decrease by 20% absolute with depth. These complexities likely involve a phase transition when the asphaltene concentration exceeds 35%. Traditional thermodynamic models of heavy oils and asphaltene gradients are known to fail dramatically. Many have ascribed this failure to some sort of chemical variation of asphaltenes with depth; the idea being that if the models fail it must be due to the asphaltenes. Our new simple formalism shows that thermodynamic modeling of heavy oil and asphaltene gradients can be successful. Our simple model demands that the asphaltenes are the same, top to bottom. The analysis of the sulfur chemistry of these asphaltenes by X-ray spectroscopy at the synchrotron at the Argonne National Laboratory shows that there is almost no variation of the sulfur through the hydrocarbon column. Sulfur is one of the most sensitive elements in asphaltenes to demark variation. Likewise, saturates, araomatics, resins and asphaltenes (SARA); measurements also support the application of this new asphaltene formalism. Consequently, the asphaltenes are very similar, and our new FHZ EoS with the Yen-Mullins formalism properly accounts for heavy oil and asphaltene gradients.
A Jurrasic oilfield in Saudi Arabia is characterized by black oil in the crest and with mobile heavy oil underneath and all underlain by a tar mat at the oil-water contact. The viscosities in the black oil section of the column are fairly similar and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large continuous increase in asphaltene content with increasing depth extending to the tar mat. The tar shows very high asphaltene content but not monotonically increasing with depth. Because viscosity depends exponentially on asphaltene content in these oils, the observed viscosity varies from several to ~ 1000 centipoise in the mobile heavy oil and increases to far greater viscosities in the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. Conventional PVT modeling of this oil column grossly fails to account for these observations. Indeed, the very large height in this oil column represents a stringent challenge for any corresponding fluid model. A simple new formalism to characterize the asphaltene nanoscience in crude oils, the Yen-Mullins model, has enabled the industry's first predictive equation of state (EoS) for asphaltene gradients, the Flory-Huggins-Zuo (FHZ) EoS. For low GOR oils such as those in this field, the FHZ EoS reduces to the simple gravity term. Robust application of the FHZ EoS employing the Yen-Mullins model accounts for the major property variations in the oil column and by extension the tar mat as well. Moreover, as these crude oils are largely equilibrated throughout the field, reservoir connectivity is indicated in this field. This novel asphaltene science is dramatically improving understanding of important constraints on oil production in oil reservoirs.
Mishra, Vinay Kumar (Schlumberger) | Skinner, Carla (Husky Energy Inc.) | MacDonald, Dennis (Husky Energy Inc.) | Hammou, Nasreddine (Saudi Aramco Shell Ref Co) | Lehne, Eric (Schlumberger) | Wu, Jiehui (Schlumberger) | Zuo, Julian Youxiang (Schlumberger) | Dong, Chengli (Shell International E&P (Rijswijk)) | Mullins, Oliver C. (Schlumberger)
It has long been recognized that condensates can exhibit large compositional gradients. It is increasingly recognized that black oil columns can also exhibit substantial gradients. Moreover, significant advances in asphaltene science have provided the framework for modeling these gradients. For effective field development planning, it is important to understand possible variations in the oil column. These developments in petroleum science are being coupled with the new technology of downhole fluid analysis (DFA) to mitigate risk in oil production.
In this case study, DFA measurements revealed a large (10×) gradient of asphaltenes in a 100-m black oil column, with a corresponding large viscosity gradient. This asphaltene gradient was traced to the colloidal description of the asphaltenes, which yielded two conclusions: the asphaltenes are vertically equilibrated, consequently vertical connectivity is indicated, and the asphaltenes are partially destabilized. Vertical interference testing (VIT) was performed at several depths and confirmed the vertical connectivity of the oil column, with four of the five tests showing unambiguous vertical connectivity consistent with the overall connectivity implied by DFA. Geochemical analysis indicates that the instability was due to some late gas and condensate entry into the reservoir. For mitigation of production risk, flow assurance studies were performed and showed that while the asphaltenes are indeed partially destabilized, there is no significant associated problem. Moreover, thin sections of core were analyzed to detect possible bitumen. A very small quantity of bitumen was found, again confirming the asphaltene analysis; however, geochemical studies and flow assurance studies confirmed that this small amount of bitumen is not expected to create any reservoir issues.
Using new science and new technology to identify and minimize risk in oil production in combination with pressure transients addressed reservoir connectivity and provided a robust, positive assessment.
Mullins, Oliver C. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Andrew, A. Ballard (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Andrew, E. Pomerantz (Schlumberger) | Dong, Chengli (Shell Exploration and Production Inc) | Elshahawi, Hani (Shell Exploration and Production Inc) | Cribbs, Myrt E. (Chevron North America)
Pastor, Wilson (Minister of Non-Renewable Resources) | Garcia, German (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Hulme, Richard (Schlumberger) | Goddyn, Xavier (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Many hydrocarbon reservoirs have an oil bearing zone, sandwiched between gas and water bearing zones. For these reservoirs, considerable studies are conducted to optimize the location of wells in the oil rim so as to maximize oil recovery. Few studies however have investigated the conditions under which wells could be located in either the gas cap or the water leg so as to also maximize oil recovery.
This study investigates the effect of gas cap and aquifer sizes on oil recovery from a reservoir with a thin oil rim using a single well numerical reservoir simulator model. Sensitivity studies were conducted by varying gas cap size, aquifer size and well location, and analyzing their effect on oil recovery.
The results indicated that for a reservoir with a large gas cap, it may be more favorable to place the horizontal well below the water-oil contact; for a reservoir with a small gas cap and large aquifer, it may be advantageous to place the horizontal well above the gas-oil contact.
This study is significant since thin oil rims are especially prominent in the prolific gas province offshore the east coast of Trinidad, and maximizing oil recovery, the more valuable resource, has positive financial implications.
Keywords: thin oil rim, gas cap drive, water drive, horizontal well.
Effective development of thin oil rims offshore Trinidad has been a challenge faced by operators over the years (Ali-Nandalal et al., 1999; Bayley-Haynes and Shen, 2003). The recovery of the oil in these types of reservoirs is often difficult because coning or cresting of unwanted fluids is inevitable and often results in low oil recovery rates. The key concern is therefore obtaining economic and optimal operations despite the gas and water coning effects that could confine production below commercial rates and hinder recovery (Vo et al., 2000; Kabir et al., 2004).
The 21 sand reservoir located in the Mahogany field is a typical thin oil rim reservoir. The field is located approximately 60 miles offshore the south-east coast of Trinidad, where the water depth is 285 feet and consist of a faulted anticlinal structure with Pleistocene age stacked sand and shale. The oil zone approximately 63-75 ft thick and is overlain by a huge gas cap and underlain by water.
Many authors have looked at both gas and water coning problems and have recommended ways to alleviate these problems in order to lengthen well or reservoir life. In recent years, the drilling of horizontal and multilateral wells has been proposed as a possible solution (Wu et al., 1995). These wells have been generally accepted as a better way to improve recovery efficiency when compared to conventional vertical wells (Vo et al., 2000). These wells however can be more costly than conventional wells and as such, effective planning is essential to the exploitation of the oil resource.
Generally thin oil rims are developed with the horizontal wells located in the oil zone. Few studies however have investigated the conditions under which wells could be located in either the gas cap or the water leg so as to further maximize oil recovery. This study investigates the effect of gas cap and horizontal well location on oil recovery from a thin oil rim with a large aquifer using a single well numerical reservoir model.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151046, "Pushing the Extended-Reach Envelope at Sakhalin: An Operator's Experience Drilling a Record-Reach Well," by Michael W. Walker, SPE, ExxonMobil, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed.