Douglas J. Seifert

Mobile Heavy Oil and Tar Mat Characterization Within a Single Oil Column Utilizing Novel Asphaltene Science

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 YenMullins formalism properly accounts for heavy oil and asphaltene gradients.

Collaborative Development of a Slim LWD NMR Tool: From Concept to Field Testing

ABSTRACT Nuclear Magnetic Resonance (NMR) was identified as a critical technology for reducing uncertainty and minimizing risk during the planning phase of a major field development project. The reservoirs in the subject field contain heavy oil/tar in the flanks, a nd accurate knowledge of viscosity trends becomes essential for the placement of water injectors. Since NMR logs can be used to estimate heavy oil viscosity, the development plan required running logging while drilling (LWD) NMR logs in the extended -reach horizontal injectors, in addition to some selected producers. A program heavily based on slim hole drilling presented a practical challenge for the execution of the development plan, since at the time no service company offered slim hole LWD NMR services. Considering the business impact of this technology gap, Saudi Aramco decided to collaborate with the service industry to develop LWD NMR technology for hole sizes ranging from 5⅞ ” to 6⅛”. Within a year, a joint project was established with a major technology provider for the development of a slim LWD NMR tool. The fi rst two prototypes were delivered for field testing in less than 18 months. The prototypes have been run in nearly a dozen wells to date and in a variety of environments, including extended-reach wells with high salinity muds. Data obtained from drilling and reaming runs agree very well with those from other porosity tools, including wireline NMR. Furthermore, close coordination and cooperation between the operator and the service provider during testing runs have resulted in significant improvements in downhole firmware, data acquisition modes and signal processing. Two factors weigh heavily for the successful fast delivery of the project goals: clear requirements from the operator, and proven expertise in NMR tool design from the technology provider. Giv en continuing reliable and robust performance from the prototypes, the slim LWD NMR service is expected to be commercially available shortly. In fact, the high level of confidence gained from early field tests has already allowed the use of the data in cri tical well placement decisions in some wells.

Integration of Downhole Fluid Analysis and the Flory-Huggins-Zuo EOS for Asphaltene Gradients and Advanced Formation Evaluation

Abstract The Yen-Mullins model of asphaltenes has enabled the development of the industry’s first asphaltene equation of state (EOS) for predicting asphaltene concentration gradients in oil reservoirs, the Flory-Huggins-Zuo (FHZ) EOS. The FHZ EOS is built on the existing the Flory-Huggins regular solution model, which has been widely used in modeling the phase behavior of asphaltene precipitation in the oil and gas industry. For crude oil in reservoirs with a low gas/oil ratio (GOR), the FHZ EOS reduces predominantly to a simple form—the gravity term only—and for mobile heavy oil, the gravity term is simply based on asphaltene clusters. The FHZ EOS has been applied to different crude oil columns from volatile oil to black oil to mobile heavy oil all over the world to address key reservoir issues such as reservoir connectivity/compartmentalization, tar mat formation, nonequilibrium with a late gas charge, and asphaltene destabilization by integrating downhole fluid analysis (DFA) measurements and the Yen-Mullins model of asphaltenes. Asphaltene or heavy-end concentration gradients in crude oils are treated using the FHZ EOS explicitly incorporating the size of resin molecules, asphaltene molecules, asphaltene nanoaggregates, or/and asphaltene clusters. Field case studies proved the value and simplicity of this asphaltene or heavy-end treatment. Heuristics can be developed from results corresponding to the estimation of asphaltene gradients. Perylene-like resins with the size of ~1 nm are dispersed as molecules in high-GOR light oils (condensates) with high fluorescence intensity and without asphaltenes (0 wt% asphaltene). Heavy asphaltene-like resins with the size of ~1.5 nm are molecularly dissolved in volatile oil at very low asphaltene content. Asphaltene nanoaggregates with the size of ~2 nm are dispersed in stable crude oil at a bit higher asphaltene content. Asphaltene clusters are found in mobile heavy oil with the size of ~5 nm at even higher asphaltene content (typically >8 wt% based on stock-tank oil). All these studies are in accord with the observations in the Yen-Mullins model within the FHZ EOS analysis. Furthermore, the cubic EOS and FHZ EOS have been extended to a near critical fluid column with GOR changing from 2600 to 5600 scf/STB and API gravity changes from 34 to 41 °API. Data from the real-time third-generation of DFA were used to establish the early time EOS for advanced formation evaluation. The early-time EOS was updated after the laboratory PVT data were available. The results from the early-time EOS based on the new-generation DFA data were in accord with those from the updated one based on the pressure/volume/temperature (PVT) data. The large GOR gradient is well modeled by the cubic EOS assuming a small late gas charge from the crest to the base. The FHZ EOS with 1-nm diameter was employed to predict the fluorescence intensity gradient. This agrees that perylene-like resins with the size of ~1 nm are dispersed as molecules in high-GOR light oil (rich gas condensate) with high fluorescence intensity and without asphaltenes (0 wt% asphaltene).

In-Situ Heavy-Oil Fluid Density and Viscosity Determination Using Wireline Formation Testers in Carbonates Drilled With Water-Based Mud

In-situ heavy oil density and viscosity can vary laterally and vertically in carbonate reservoirs. The spatial distribution of these PVT properties must be determined accurately for reserve assessment, reservoir simulation, well placement and other field development processes. Although laboratory PVT analysis is the industry-standard source for fluid properties, the extensive time required to restore and process heavy oil fluid samples often minimizes the impact of such information during the drilling phase. The use of wireline formation testers, capable of measuring in-situ density and viscosity, can greatly aid the decision-making process providing timely basic PVT data, in addition to guiding the fluid sampling program and increasing the quality of the samples to be taken. While in-situ measurement of fluid density and viscosity in oil-based-mud is well-established, accurate determination of such properties can be quite challenging in water-based-mud environments; especially in those cases of water-dominated flow, strongly emulsified fluids or high fraction of sediments in the flow line. Several techniques, such as sampling point optimization, pressure and flow rate control during pump-out, and tool-string configuration can minimize the adverse effects, thereby improving measurement and sampling quality. Yet, there can still be cases where the measurement accuracy can be limited due to the specific combination of fluid and formation properties, and borehole conditions. In this paper, several case histories in a variety of borehole and mud conditions, including highly deviated and ultra-reach extended horizontal wells, are presented with comparisons to laboratory data when available. Results indicate that accurate in-situ density and viscosity determination is possible when sufficient amount of oil is present in the flow line. Experience also shows that measurement quality can be affected in suboptimal conditions involving strong emulsions, or range of viscosities outside the sensor specifications. Introduction Field development strategies for heavy oil reservoirs are often based on the knowledge of porosity, water saturation and permeability – as in the case of conventional reservoirs containing light oils. Although these properties and the inherent heterogeneities affect the production characteristics of a heavy oil reservoir, the impact of variations in fluid properties such as density and viscosity can be considerable – and more significant – in many cases (Larter et al., 2008). While permeability in a heavy oil reservoir may vary from a milidarcy to a darcy, in-situ viscosity may easily vary from a few to hundreds of thousands of centipoise, creating enormous variations in fluid mobilities that lead to highly irregular reservoir production patterns. In general, all heavy oil field characterization and development processes, including well placement, reserves assessment, welltesting and simulation, require accurate knowledge of in-situ fluid properties for optimal results. Viscosity is especially important because of its strong imprint in fluid mobilities. In-situ viscosity determined from laboratory PVT analysis is widely considered the ground truth for fluid properties. In the case of heavy oils and water-based-mud (WBM) drilling, PVT studies may take several