Removing Formation Damage and Stimulation of Deep Illitic-Sandstone Reservoirs Using Green Fluids
- M.A. Mahmoud (AkzoNobel) | H.A. Nasr-El-Din (Texas A&M University) | C.A. DeWolf (AkzoNobel)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 30 October-2 November, Denver, Colorado, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 1.6 Drilling Operations, 2.4.5 Gravel pack design & evaluation, 6.5.4 Naturally Occurring Radioactive Materials, 2.4.3 Sand/Solids Control, 5.5.2 Core Analysis, 1.8 Formation Damage, 5.8.7 Carbonate Reservoir, 5.2 Reservoir Fluid Dynamics, 4.2.3 Materials and Corrosion, 5.1.1 Exploration, Development, Structural Geology, 3.2.4 Acidising, 2.7.1 Completion Fluids, 4.3.4 Scale, 1.11 Drilling Fluids and Materials, 1.6.9 Coring, Fishing, 4.3.1 Hydrates, 1.4.3 Fines Migration, 4.1.2 Separation and Treating
- 5 in the last 30 days
- 629 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 8.50|
|SPE Non-Member Price:||USD 25.00|
Illitic-sandstone reservoirs are very sensitive to HCl-based fluids. When HCl contacts illitic-sandstone it breaks down and causes fines migration and formation damage. The migration of fines through the porous media will block the pores, reduce permeability and decrease the production rate of oil and gas wells. Literature showed that all clay minerals are essentially unstable in HCl at temperatures greater than 300oF. In turn, there is an essential need to look for stimulation fluids other than HCl to stimulate deep sandstone reservoirs.
Alternative fluids to HCl/HF mud acids were introduced to stimulate and remove the damage from illitic-sandstone reservoirs. These fluids are chelating agents such as EDTA (ethylene diamine tetraacetic acid), HEDTA (hydroxyl ethylene diaminetriacetic acid), and GLDA (glutamic acid-N,N-diacetic acid). In this study, sandstone cores with different illite contents were examined. Illite content of 1, 10, 14, and 18 wt% of the sandstone cores were used in the coreflood experiments
at 300oF. Different combinations of GLDA/HF were tested to determine the optimum ratio of GLDA/HF. CT scan and permeability measurements before and after the treatment were used to assess the effectiveness of each fluid in removing the damage and stimulation of sandstone cores.
Our results showed that 15 wt% HCl caused severe damage to sandstone cores with different illite contents. GLDA, HEDTA, and EDTA showed a good compatibility with the illitic-sandstone cores at 300oF. Permeability measurements and CT scan results showed that GLDA performed better than HEDTA and EDTA at pH of 4. The optimum ratio of GLDA/HF concentration was found to be 20 wt% GLDA/1 wt% HF, which gives the maximum increase in core permeability. The three fluids tested in this study showed good compatibility with illite. They can be used to stimulate illitic-sandstone reservoirs alone or in combination with HF acid. GLDA was found to be compatible with the sandstone cores that contained up to 18 wt%. No sands deconsolidation was noted with any of the three fluids. The results obtained from this study will significantly improve the outcome of acid treatments in illitic-sandstone reservoirs at high temperatures.
The objective of stimulation of sandstone reservoirs is to remove the damage caused to the production zone during drilling or completion process. Sandstone acidizing consists of three main stages of sandstone acidizing: (1) a preflush, normally of hydrochloric acid, (2) a mud-acid stage of hydrochloric and hydrofluoric, and (3) an after flush that may be hydrochloric acid, an aqueous solution of non-damaging salt such as ammonium chloride or clean hydrocarbon solvent such diesel oil (Gidley 1996).
Clay minerals are extremely small, platy-shaped materials that may be present in sedimentary rocks as packs of crystals. The
maximum dimension of a typical clay particle is less than 0.005 mm. The clay minerals can be classified into three main
groups: (1) Kaolinite group, (2) Smectite (or Montmorillonite) group, and (3) Illite group. In addition, there is mixed-layer
clay minerals formed from several of these three basic groups. The following table indicates the chemical structure of the
different types of clay minerals (Civan 2000). The interactions of the clay minerals with aqueous solutions are the primary
culprit for the damage of petroleum-bearing formations. The rock-fluid interactions in sedimentary formations can be
classified in two groups: (1) chemical reactions resulting from the contact of rock minerals with incompatible fluids, and (2)
physical processes caused by excessive flow rates and pressure gradients.
|File Size||1 MB||Number of Pages||16|