TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFor many years, unfiltered produced water has been used in the flooding of heavy oil reservoir in Southern Oman for pressure maintenance. Initially it was thought that the water injection was under matrix conditions. However, it is well accepted in the industry that water injection and particularly produced water injection almost, always takes place under fracturing condition. Significant decline in injectivity was repeatedly seen due to downhole blockages. Routine clean-ups and acidizations were carried out without success. Early 2003, a dedicated study was conducted to identify the root cause of this problem and recommend a remedial action. The purpose was to determine if the decline is due to poor water quality, reservoir compartmentalization, matrix/fracture or wellbore plugging.An unconventional approach was used to conduct a comprehensive study using historical data by modifying the Hall-Analysis technique. It was concluded that poor water quality was the problem. The interpretation of the Modified Hall Plot together with Bottomhole Pressure (BHP) vs. Rate plot also provided evidence of wellbore and/or fracture plugging. Both qualitative and quantitative analyses characterized the initial matrix injection period and fracturing injection regime that followed. Fracture plugging, routine well stimulations and fracture propagation trends were interpreted from the plots. A 3D in-house simulation package for waterflood under fracturing conditions was used, independently, to simulate injection conditions and confirm the results. Simulated injection pressure was much lower than actual field data confirming severe plugging. Further analysis showed that the plugging was due to unconventional particulates different from solids and oil contaminants in water. Recommendation was made to identify the contaminant and maintain a maximum suspended solid concentration of 100ppm to contain fracture propagation. A recent filter trial confirmed the presence of FeS contaminant.Successful remedial action was taken followed by recommissioning and water treatment facility design to realize estimated 150m3/d/well and improving ultimate recovery. Recently, another field study has successfully completed adopting same technique. By modifying Hall Analysis technique, it is possible to use field data for diagnosing matrix/fracturing regimes, assessing degree of damage and determining the location of the damage.
Profile modification of injection and production wells is of major importance in South Oman heavy oil reservoirs. This is because injected and produced water must be controlled to optimize reservoir sweep and oil production. Profile control in artificial lift wells is also a common dilemma because the intervention involves re-completing wells to achieve logging-while-pumping necessary for detecting unwanted intervals. In 2004, two completion philosophies were adopted to allow hoist-free re-entry as well as provide a cost effective life-cycle solution. One is the replacement of smart wells with segmented horizontal wells. This completion allows for effective diagnosis and isolation of watered-out sections. The other is replacing the upper completion of producers in sub-hydrostatic reservoirs with dual Christmas Trees. That makes it possible to measure the inflow profile while pumping through the second tubing. A proactive measure was taken by field-testing a new technology capable of satisfying all basic requirements. The technology is a wireline deployed rubber and carbon fiber sleeve expanded by hydraulic pressure to set flush against the casing. Heat is applied to polymerize the resin before deflating and retracting the running tool. The patch thickness can withstand both burst and collapse pressures, leaving sufficient internal-diameter in 7-in and 4 ½-in casing for subsequent deeper intervention. Phase-1 trial was successfully completed in 3 water injectors late in 2004. Phase-2 trial which was planned for 2 oil producers are still being mobilized and will be executed in third quarter of 2005, late for publication in this paper. Some unique characteristics of this technology made it attractive; namely (1) ability to deploy via smaller size tubing to expand & set in larger perforated liners, thus eliminating rig/hoist requirement, (2) high depth precision using CCL correlation, (3) possibility of bypassing existing patch to isolate downstream toe area, (4) possibility to by-pass isolated areas to re-perforate lower zones and safely retrieve the bloated gun barrels, (5) applying gentle and even hydraulic force contour-to-contour to set against un-reinforced liners, (6) cost effective solution of higher success rate compared to chemical treatments. The trials proved to be the first campaign of its kind to be successfully completed with 100% success rate, while meeting all expectations. Introduction As part of the new effort to reverse the trend of increasing water cut in Petroleum Development Oman (PDO), both mechanical and chemical profile control initiatives have been widely pursued in the Southern and Northern Directorates. PDO currently produces 630,000 bbl/d of oil with about 3.6 Million bbl/d of water - 85% water cut (WC) - and this is expected to remain on the rise unless life cycle remedial solutions are implemented to mitigate this trend in both the existing and new wells. Southern & Northern Oman Directorates are predominantly sandstone and carbonate formations respectively, meaning that their development challenges and costs are somewhat dissimilar. Also, formation & reservoir fluid properties are known to vary widely from North to South. Due to these differentiating qualities, a viable optimization solution in the South might not be found optimal in the North and vice-versa. For example, the South mainly employs a lot of Beam (Rod) Pumps and some Electric Submersible Pumps (ESPs) while the North depends mainly on Electric Submersible Pumps (ESP) and Gas Lifts. While these directorates are currently operated as two different business units in terms of development methodologies, optimization techniques, etc, they however share one common goal of maximizing production at a reduced operating expenditure. The primary aim being to restore oil production to 800,000 bbl/d over the next few years.
This study set out to investigate how Nigerian oil rig rates respond to oil price fluctuations, and the lag between them aimed at developing models for forecasting land, swamp and offshore rigs rates in Nigeria. The research methodology involves application of Ordinary Least Squares regression to develop models that can predict land, swamp and offshore rig rates, which can be used in the Nigerian market. Firstly, Brent crude oil prices are exogenous to Nigeria, whilst land, swamp or offshore rig rates are endogenous. Furthermore, these exogenous variables are regressed with and without lag to test the response time between the cause and its effect. A striking relationship is observed between these independent variables similar to global trends. Like other countries, the Nigeria oilrigs count trends along with Brent crude oil price. However, a 3-4 months lag exists between Nigerian rig rates and oil prices. Furthermore, the model estimation using one-year lag seems to show more accuracy in matching the historical rig rates and the more expensive the rig, the wider the margin caused by oil price changes. This confirms the possibility to predict Nigeria rig rates and perhaps, well costs from oil price forecast.
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