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Conventional primary and secondary water flooding of Deepwater Gulf of Mexico (GOM) reservoirs typically result in substantial un-recovered oil providing an attractive target for enhanced oil recovery (EOR) processes. One of the challenges of applying EOR gas injection in these offshore reservoirs is the h igh oil asphaltene content. Anadarko Petroleum Corporation and Schlumberger have jointly investigated the effects of gas addition on the phase behavior of oil, especially its effect on asphaltene precipitation and deposition. The study focuses on the experimental results from various tests showing the instability of asphaltenes in oil from various gas injection scenarios. Three common EOR injection gases: nitrogen (N2), carbon dioxide (CO2) and methane (CH4) were studied. N- heptane was (n-C7) also included for comparison of solids phase behavior during depressurization. Most asphaltene laboratory testing use n-C7 at ambient conditions, whereas asphaltene precipitation occurs with change in pressure and temperature during reservoir depletion processes. The study collected PVT and flow assurance data for original live fluid and for additions of N2, CO2, CH4 and n- C7 at high pressure and temperature conditions. Measurements include asphaltene onset pressure (AOP), saturation pressure (Pb), swelling tests and asphaltene deposition tests. Other basic measurements of the corresponding dead oil include SARA analysis, viscosity, density and fluid characterization. Fluids from the field presented a compositional variation with a variety of asphaltene contents from 4 to 15.5%. Results of experimental flow assurance assessments revealed the black oil has high propensity for asphaltene precipitation due to addition of injected gas. The addition of N2, CO2 or CH4 significantly aggravates the asphaltene precipitation condition of these fluids. The comparison between the three gases showed that, when added in the same mole proportion, N2 was the strongest precipitant followed by CH4.

The asphaltene content effect on crude oil properties was investigated for a series of deepwater Gulf of Mexico (GOM) fluids with asphaltene contents varying from 4 to 15 wt %. The objective of the study was to conduct flow assurance screening tests on GOM samples collected from different sands and determine properties of the dead oil and the asphaltene stability. Densities, refractive indices, and viscosities were measured at different temperatures in dead oils with three different asphaltene contents. The properties showed defined tendencies with the asphaltene content and with the temperature. The application of the one-third rule in the calculation of properties, such as solubility parameter and viscosity of dead oil systems, was evaluated. This approach also provides an alternative to calculate the refractive index based on densities obtained from an equation of state. The analysis also shows the important role that the asphaltene content plays in determining the viscosity of crude oil and evaluates the possibility of predicting viscosity from refractive index, as proposed by Vargas et al. Another important aspect to evaluate is the prediction of the asphaltene stability in the crude oil by measuring basic dead oil properties, such as density and refractive index. The asphaltene instability trend (ASIST) method was used to predict the asphaltene precipitation onset at reservoir conditions. In this analysis, the asphaltene stability was studied on the heaviest and lightest samples (high and low asphaltene content) by determining the minimum quantity of precipitant required to initiate asphaltene flocculation, followed by measurement of the refractive index of the mixture at the onset conditions. The asphaltene precipitation kinetic effect was also considered in this study.

K2 is a large Gulf of Mexico offshore oil field located in Green Canyon Blocks 518 and 562 approximately 175 miles south of New Orleans, Louisiana (Figure 1). It is one of the first deepwater subsalt Miocene fields to begin production from reservoir depths below 25,000 feet SSTVD. Since first production in May 2005, the field reached a peak production rate of 40,000 bopd before following a continuous decline rate. Well performance analysis and reservoir simulation history match results indicate the main producing M14 and M20 sands lack any substantial natural drive recovery mechanisms. The potentially huge oil resource, that could go unrecovered, justified efforts to evaluate the feasibility of various injection processes to maximize ultimate oil recovery. Initial screening resulted in seawater and nitrogen injection as the most technically and economically viable oil recovery methods. The process selection stage is in progress to evaluate these two recovery methods. K2 field delineation and reservoir studies are in progress and much additional work (including geomodeling and reservoir simulation using fluid and core experimental studies) will be performed prior to selection of a suitable recovery process to proceed to the project definition stage. The purpose of this paper is to document the design and initial results of EOR and flow assurance fluid studies to be used in evaluation of the feasibility of nitrogen gas injection for recovery of substantial incremental oil over pressure depletion. Conventional EOR laboratory studies were complicated by the need for flow assurance considerations due to the deepwater offshore environment and high asphaltenes content of the main producing horizon EOR target M14 oil zone. Also, it became important for laboratory testing to thoroughly evaluate the EOR process mechanisms and provide rigorous data for reliable reservoir modeling and simulation. Unlike onshore EOR projects, implementation of an EOR project in K2 would have to be done without the benefits of a pilot flood to fully test the EOR process and provide design data for the fieldscale project. This is due to the prohibitive cost and time for the facilities, equipment, and wells needed to conduct a producing nitrogen injection pilot test in the deepwater offshore environment and subsalt reservoir depths below 25,000 feet. Results of the initial laboratory work revealed new and different ideas to suggest novel directions in how fluid studies and flow assurances issues should be addressed in evaluating an EOR process for deepwater offshore application. We conclude from the findings thus far:surface separator fluid samples can be successfully recombined to obtain representative reservoir fluids for PVT, EOR, and flow assurance work,asphaltene stability tests resulted in a substantial increase in the AOP with increase in the solution GOR and a greater effect for hydrocarbon vs nitrogen gas, andimproved procedures for experimental slim tube tests can provide more representative determinations of miscibility pressures. A comprehensive strategy and program for fluid sampling and laboratory fluids testing has been prepared and is being implemented. Basic fluid properties and PVT data have been measured. Initial results of miscibility, PVT, and flow assurance lab tests with nitrogen and reservoir oil mixtures are presented. The lessons learned from the initial lab work provided new insights and ideas for planning fluid sampling and lab testing programs for operators to evaluate other reservoirs for gas injection EOR processes in deepwater offshore environments.

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