Hydraulic Fracturing With Heated Fluids Brings Success in High-Pour-Point Waxy-Oil Reservoir in India

Abstract

Summary Most existing production of waxy oils occurs in high-permeability formations, and wax issues are mostly a problem in the production tubing or pipeline. Large reserves also exist in low-permeability formations that require hydraulic fracturing for economic production. Such a reservoir was recently discovered in Rajasthan, northwest India, overlying a more typical high-permeability formation, both with high-pour-point waxy oil. Because a very large amount of oil in place is present in the low-permeability formation, two fracturing campaigns were performed in two different horizons to assess the potential for successful well stimulation. The first fracturing campaign (on four wells) showed limited success. A study was performed to determine the reason for the failure, and significant changes were made for the second campaign. This paper documents the second campaign. This campaign featured the first successful use in India of heated fluids to stimulate a shallow, low-permeability, massive oil reservoir containing high-pour-point waxy oil. Introduction Numerous exploration and appraisal wells have been drilled in the RJ-ON-90/1 Block in Rajasthan, northwest India, targeting primarily the prolific Fategarh reservoir (Zittel et al. 2008). Many of these wells have encountered hydrocarbon-bearing-potential reservoir-quality rock in the shallower Barmer Hill formation. Fig. 1 shows the field locale, which is situated just east of the border with Pakistan. The Barmer Hill formation is a shallow (700 to 800 mTVDSS), rich to very-rich source rock and has been described generally as siltstone and claystone, with gas peaks and frequent oil shows. Because the source rock is lacustrine in origin, it has generated waxy oil. Fluid analysis from the Barmer Hill reservoir shows high pour points (>45°C), wax appearance temperature (WAT) several °C less than reservoir temperature (˜70°C), and in-situ viscosities of tens of centipoises. The in-place hydrocarbon may be large, especially in the north of the basin because of the Barmer Hill's high porosities (25-30%). Producing these hydrocarbons, however, is not easy. Natural-flow openhole tests in three separate wells in the northern fields showed mixed-to-poor results and very low permeability (1-10 md), as estimated from slug-flow-well test analysis. To prove the commercial potential of the Barmer Hill reservoir, a hydraulic-fracturing campaign was conducted.

Cyclic waterfrac stimulation to develop an Enhanced Geothermal System (EGS)—Conceptual design and experimental results

“…those using water), gelproppant fracs or a combination of both called hybrid fracs (Sharma et al, 2004). The procedures are well known in the hydrocarbon industry (Shaoul et al, 2007(Shaoul et al, , 2009) as well as in Hot Dry Rock (HDR) technology Hettkamp et al, 2004;Schindler et al, 2008), and have also been applied to hydrothermal systems (Legarth et al, 2003. Compared with hydrocarbon reservoir stimulation (Economides and Nolte, 2000), application to geothermal systems requires techniques that will radically increase fluid production to make a project economically feasible.…”

In-Situ Stress Test Data – Revelation to Optimization of Stimulation Strategy of an Unconventional Reservoir

“…Hydraulic fracturing treatments were carried out in 2006 in wells from the Mangala and Aishwariya fields each in the Barmer Hill reservoirs 1 (Shaoul et al, 2009). After hydraulic fracturing, the well in Mangala Field started production at 160bbls/day with the aid of a Sucker Rod Pump (SRP) but declined to a final production rate of 30bbls/day after one month of extended well testing (Figure 4).…”

Reservoir Characterisation of the Low Permeability Siliceous Barmer Hill Formation, Barmer Basin, India

“…Hydraulic fracturing treatments were carried out in 2006 in two wells from the Mangala and Aishwariya fields in the Barmer Hill porcellanite reservoirs (Shaoul et al, 2009). After hydraulic fracturing, the Mangala-field well started production at 160bbls/day with the aid of a Sucker Rod Pump (SRP) but declined to a final production rate of 30bbls/day after one month of extended well testing (Figure 9).…”