Long horizontal and multi-lateral oil and gas wells provide an attractive option for maximizing reservoir contact. Formate-based brines have been used in drilling and completion operations for more than 10 years. Advantages of these fluids include high density, solids-free brines, better compatibility with XC-polymer, starches, and less potential for formation damage. These advantages were reported in several previous publications.
Filter cake of drilling fluid can act as a barrier to the fluid flow in both cased and openhole wells. Calcium carbonate particles are frequently used as weighting material to maintain the pressure that is required for well control and minimizing leak-off rate. These solid particles become consolidated and trapped in a polymeric material and this makes the filter cake a very effective permeability barrier.
The conventional method for cleaning filter cake is by using solids free formate brines, either by soaking or circulating for many hours at high flow rates. This mechanical technique removes only external filter cake. Chemical means like acids, oxidizers or enzymes are usually used as an alternative method for dissolving both the external and internal filter cake. Most of these fluids cannot give a full coverage to the wellbore due to the formation heterogeneity.
A new precursor (ester of an organic acid) can generate an acid downhole at a low release rate, which results in uniform fluid distribution through the wellbore. Compatibility and thermal stability tests between the precursor solution and formation brine were studied in detail. Return permeability experiments were conducted by using HPHT dynamic fluid loss cells. The ester solution was effective in cleaning the filter cake in comparison to the formate brines.
A field application, where formate brine was used to drill and complete a gas producer in a sandstone reservoir is included in this paper. The gas well was drilled in a weakly consolidated reservoir, and was completed with expandable sand screens (Inconel 825). The bottom hole temperature is 300°F. The produced gas contains 2–3 vol% carbon dioxide and no hydrogen sulfide. Full analysis of flow back samples indicated that most of the returned solids are calcium carbonate. Lab tests indicated that the ester solution can be used to restore well productivity by removing damage induced by the drilling mud filter cake.
Khuff and Pre-khuff gas-condensate reservoirs in Saudi Arabia have been on production for more than ten years. Many of these wells are classified as sour gas producers with hydrogen sulfide levels up to 10 mol% and carbon dioxide at 4–5 mol%., Table 1.1 T-100 is the first 5-? in. deviated gas well in Field T. The targeted reservoir in this well is Unayzah-A reservoir.
The gas reservoir is sandstone. The mineralogy of the rock at the subject well was not available, therefore, the mineralogy of an off set well (well T-800) will be discussed. Table 2 shows that the rock contains mainly quartz, clays, and feldspars and carbonate minerals. This mineralogy can affect stimulation efforts in this reservoir in several ways. Clay particles include illite and kalinite. Illite is sensitive to HCl, whereas kalininite can cause fines migration if the drilling or completion fluids have lower salinity than the native formation brines. Illite/smectite mixed clay can cause clay swelling. Potassium chloride is added to both drilling and completion fluids to avoid clay swelling and or fine migration problems. The rock contains carbonate minerals which should be removed if an HF-based acid is to be used to stimulate this formation. The presence of iron-based minerals (ankertie and pyrite) highlights the need to use an iron control agent.
The reservoir temperature and pressure are 300°F and 8,535 psi, respectively. Well T-100 was re-entered, sidetracked, and drilled as a highly slanted well, with an angle of 81o, to a total depth of 16,747 ft measured depth (15,130 ft total vertical depth). The well completion includes 4 in. expandable sand screen (ESS). The ESS was successfully run to a depth of 16,606 ft. This was 141 ft from the bottom, as the screen assembly stopped. The screen could not be pushed any further due to the fragility of the screens with maximum allowable hole drag of 60,000 lb.2 The ESS was then expanded to 6.125 in. OD and 5.125 in. ID down to 16,600 ft, Photo 1. The porosity and permeability core plugs obtained from the subject well were measured; Fig. 1. Expandable sand screen was selected to provide downhole sand control and ultimately will reduce the friction pressure loss and sanding problems. Well T-100 was the second well drilled by using formate-based drilling fluid in Saudi Arabia.