Multiple contact miscible floods involving the injection of relatively inexpensive gases into oil reservoirs represent one of the most cost effective enhanced oil recovery processes currently available. The experimental displacement procedures available for determining the optimal flood pressure, referred to as the minimum miscibility pressure (MMP), are both costly and time consuming. Hence, the use of a correlation proven reliable over a large range of conditions would likely be considered acceptable for the purposes of preliminary screening studies. This paper presents an evaluation of 15 rich gas, lean gas, and nitrogen MMP correlations published in the literature. Each method was developed using experimental data, equation-of-state (EOS) predictions, or a combination of the two. The accuracy of each correlation was evaluated by comparing predicted versus measured MMP's using a data base consisting predominantly of experimental results published in the literature. The most reliable MMP correlations were all found to have a common EOS developmental basis. These results support the applicability of EOS-based methods for accurate MMP predictions. Introduction The injection gases most commonly used for enhanced oil recovery processes are generally not miscible upon first contact with the reservoir fluids that they are displacing. However, under suitable reservoir pressure and temperature conditions, miscibility may gradually be developed between some injection-gas/reservoir-oil combinations by a mass transfer of components between the gaseous and liquid phases. Miscibility generated in such a manner is commonly referred to as multiple contact (dynamic) miscibility, and has been well described in the literature(1). The vaporizing gas drive (VGD) and the condensing gas drive (CGD) are the mechanisms through which dynamic miscibility is generally explained. Miscibility develops at the flood front during VGD processes, which are commonly referred to as lean gas (LG) drives. Dynamic miscibility in nitrogen (N2) floods similarly occurs through the VGD mechanism. During CGD processes, generally referred to as rich gas (RG) drives, miscibility develops at the injection point. Recent research has indicated, however, that miscibility in some RG drives may actually develop through a liquid extraction drive (LED) process(2,3). Similar to VGD's, miscibility develops at the flood front during a LED. An optimum displacement pressure exists for a dynamic miscible flood, commonly referred to as the minimum miscibility pressure (MMP). The object of this study is to evaluate available RG, LG, and N2 MMP correlations using a data base consisting predominantly of experimental MMP results published in the literature. Measurement and Prediction of MMP's The MMP for gas/oil mixtures has traditionally been measured by performing slim tube displacement experiments(1). These experiments involve constant temperature displacement of a live oil from the slim tube by an injection gas. The MMP has typically been accepted as the pressure at which a practical maximum recovery efficiency is observed following a series of displacements. MMP values have also been measured for many gas/oil pairs using the Rising Bubble Apparatus (RBA)(4), where a small bubble of gas is injected at the base of a column of live oil.

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Pan Canadian Petroleum Limited, operator of the Weyburn Unit in southeastern Saskatchewan, Canada, has been involved in the development and application of underbalanced and multi-lateral drilling technologies to access reserves which otherwise were likely to be uneconomic to develop. In an attempt to optimize the mature waterflood in the Weyburn field, both vertical and horizontal infill wells have been drilled over the last 12 years. The most success has been realized from horizontal wells, which have evolved from single laterals to dual laterals to quad laterals. The combination of multi-lateral wells and properly designed underbalanced drilling techniques has resulted in increased reservoir access, significant decreases in the cost of reservoir access, and decreased formation damage. Continued exploitation of remaining reserves has been accomplished by progressively pushing the development of new technology to meet the changing economic and technical demands imposed by drilling in different parts of the Unit. Introduction Discovered in 1954, the Weyburn Unit covers an aerial extent of approximately 180 square kilometers. The Unit is located in southeastern Saskatchewan, Canada, and has been operated by Pan Canadian Petroleum Limited since 1963. The geographic location and the current level of horizontal development in Weyburn are illustrated in Figure 1. The Weyburn field was initially developed with vertical wells on 32 ha spacing. A field-wide waterflood was initiated in 1964 using 151 inverted nine-spot patterns. Eventual production declines in the Unit led to an infill drilling phase which occurred between 1985 and 1992. A total of 157 vertical infill wells were drilled on both 24 and 16 ha spacing during this time period. By 1992 it became clear that the drilling of additional vertical wells in the Weyburn Unit would not be economic. This was largely due to the following factors:Remaining vertical infill targets had limited reserves (less than 4 meters of pay and an effective wellbore radius of less than 100 meters),Problems were encountered in effectively stimulating the pay zone without breaking down into an immediately underlying highly permeable water-saturated zone, andProblems with primary cementing of zones with different pressures and geomechanical properties frequently resulted in ineffective zonal isolation and high water cuts. In 1991 and 1992, the Unit experimented with overbalanced and underbalanced single lateral horizontal wells in an attempt to overcome the completion and reservoir access problems encountered during the vertical infill programs. The success of the underbalanced pilot program led to the commercial application of single lateral horizontal and underbalanced drilling (UBD) technologies in 1993. A direct relationship was soon established between production results and reservoir quality; satisfactory production results were generally obtained from the single lateral wells drilled underbalanced into the highest quality reservoir, while those wells drilled into lower quality pay typically resulted in uneconomic production rates.

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RasGas Company Limited has been utilising the ExxonMobil Fast Drill Process to drive continuous improvement in drilling operations in Qatar's North Field since its roll-out in 2005. Implementation of the process has resulted in significant increases in drilling performance and unique changes in operational practices. In recent years, continued North Field development in new areas has introduced unique challenges requiring innovative drilling solutions to continue to raise the bar in drilling performance. This paper details how RasGas has utilised the Fast Drill Process to identify and extend new performance limiters in wells of increasing drilling complexity. It also details the development and roll-out of a new Flat Time Reduction initiative that targets performance improvement in areas previously untouched by the Fast Drill Process workflow. The combined impact of these initiatives has resulted in another step change in performance and well delivery in more complex areas of the North Field. The performance improvements have accumulated cost savings in excess of $250 Million USD for RasGas and its Shareholders and have been achieved while maintaining and building upon an industry leading safety record. The performance improvement initiatives described in this paper are applicable for any large scale drilling campaign that requires increased Rate of Penetration (ROP), reduced plateau times, and accelerated well delivery.