The use of public-private partnerships (PPPs) for infrastructure development has received significant scholarly attention of late, but there remains a need for more work at the programme level. Specifically, there is a need for work that recognizes the way that PPP programmes are implemented differently in different regions, thereby progressing beyond an effectively 'one size fits all' view of PPP programmes. In response, this paper offers a comparative analysis of the historical development trajectories of three contemporary PPP programmes: in British Columbia (BC) (Canada), Victoria (Australia) and South Africa. We begin by recognizing the role played by the UK's private finance initiative as a programme model, and then show how this model was adapted and modified in each of our cases, leading to very different field structures. The study uses a grounded theory building approach and draws heavily on theories of institutional change and structuration. There are two main contributions from this study: (1) we draw attention to the need for a context-specific approach to explain and predict PPP field development and (2) we develop arguments relating to institutional systems and processes that can guide future studies of these and similar fields.

This paper is a case history describing fracture optimization of low-permeability highly-stratified stacked turbidite sandstone reservoirs of the B interval of the Elk Hills Field. The occurrence of high-permeability, high-pressured water saturated sands immediately above and/or below the objective oil sands poses a major challenge. Integration of improved petrophysical understanding, geoscience techniques, hydraulic fracture model calibration and on-site, real-time execution has achieved a two-fold oil production increase in the south east nose area of the field while limiting water production to a 40% increase. Downhole tiltmeter measurements are incorporated to calibrate the fracture model and limit fracture height growth, thus regulating fracture conductivity to the oil saturated reservoirs, and minimizing contact with the adjacent wet zones. To date, results from surface tiltmeter1 measurements completed during twenty six fracture stages have been used with the downhole tiltmeter2 data and reservoir characterization to optimize the ongoing redevelopment from a peripheral waterflood to a pattern flood. Introduction Elk Hills Oil Field is located on the west side of the southern San Joaquin Valley of central California. It is positioned 20 miles southwest of Bakersfield and approximately 10 miles northeast of Taft (Figure 1). The Field was designated as the Naval Petroleum Reserve No.1 in 1912 to provide oil to the Navy in the event of a national emergency. Elk Hills Field produces oil and gas from several reservoir intervals highlighted on the stratigraphic column, (Figure 2). Production depths range from 1,100 to 9,500 ft, TVD. Initial production was established in 1911 from Pliocene age sands of the Shallow Oil Zone where production is related to a broad surface anticline with prominent topographic relief (Figures 1–2). In 1941, Stevens sands of the upper Miocene Montery Formation were found to be productive on the 31S structure, the largest of three deep structural anticlines at Elk Hills (Figures 2–3). Primary Stevens reservoirs on the 31S feature include the Main Body B (MBB) and Western 31S (W31S) of the B interval, and the younger, prolific 26R pool (Figures 3–5). Secondary objectives include sands in the B Shale zone and the siliceous shales or sands in the NA and CD Shale zones that lie above and below the B interval, respectively. MBB/W31S reservoirs occur at an average depth of 6,500 ft and exhibit 2,800 ft of vertical closure between the up-dip pinchout of the sands near the anticlinal crest and the Oil-Water Contact at −6,800 ft, subsea depth. These zones have abnormal reservoir pressure (0.50 psi/ft), good permeability (10 to 250 md, air permeability) and thick net pay development (300 to 500 ft). MBB production was held in reserve with only periodical tests until the energy crisis of the mid-1970's. In 1976, the U.S. Department of Energy (DOE) began producing the interval at initial rates ranging from 500 to 2000 BOPD per well.

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