The CaraCara field in the Los Llanos area of Colombia is a highly permeable (1 − 3 Darcy) sandstone with more than 10% total clay content, producing heavy crude. Gravel packing is required to avoid sand production. However, the Productivity Index after conventional gravel packing is only 50% of the open-hole potential due to drill-solids—calcium carbonate —plugging the matrix and fines migration. Non-acid and acid based preflushes have been used to dissolve the drill-solids and fines in the critical near wellbore matrix respectively. However, corrosion, uncontrolled filter cake dissolution, sludging with heavy crude and disposal of spent acid limits the use of acid pre-flushes. A recently developed non-acid based fluid capable of stimulating high temperature sandstone formations was taken as the starting point to develop a customized solution to remove formation damage and control fines migration for this particular application. The base fluid is chelant such as diammonium EDTA (DAE) to which a low concentration of HF acid is added, most commonly in the form of ammonium bifluoride. The HF acid greatly increases the dissolution of aluminosilicates, while the chelant prevents the precipitation of silica gel. The addition of boric acid effectively retard the dissolution rate of the fluid as boric acid the reacts with the HF acid to form fluoroboric acid (HBF4) which slowly hydrolyses to release HF acid. Fluroboric acid also provides an effective means of fines migration control. By adjusting the concentration of acid salts in the fluid as a function of temperature the fluid can provide effective controlled filter cake removal, matrix stimulation and fines migration control, at temperatures between 120 and 300°F. The newly developed non-acid fluid system provides some unique advantages for gravel packing and matrix stimulation applications in highly permeable heavy oil reservoirs 1) A single carrier fluid, eliminating the need for preflushes 2) Controlled filter cake dissolution ensuring circulation is maintained while gravel packing horizontal wells. 3) Effective fines migration control. 4) Scale inhibition. 5) Crude compatibility and negligible corrosion rates. In one field the average productivity index of vertical wells completed using this fluid increased from 0.2 bbl/psi to 0.9 bbl/psi. The final skin values were close to zero and the production remained stable for an extended period of time. A similar fluid when used in horizontal well applications reduced the cleanup time from days to hours. The ability to stimulate while gravel packing optimizes the productivity of dirty sandstones while minimizing the cost.

In the Llanos basin of Colombia, there are shallow, highly permeable, poorly consolidated sandstone reservoirs close to oil-water contacts. The Carbonera formation is typical—several small, highly permeable (600 to 3000 mD) producing sands, with poorly defined barriers. High production rates and low bottom hole flowing pressures (BHFP) result in water coning and sand production. One solution is a stacked frac-pack completion. In these applications, conventional cross-linked fracturing fluids have limitations. High polymer concentrations and viscosity are required to control fluid leak-off and create a sufficiently wide hydraulic fracture to admit proppant. High fluid viscosity has led to uncontrolled fracture growth into oil-water contacts, while the high polymer concentration decreases fracture conductivity and effective half-length. A linear fluid comprised of polyacrylamide and polysaccharide polymers has proved an effective solution. The polyacrylamide greatly enhances fluid efficiency and elasticity, while reducing friction pressures and horsepower requirements. Fluid elasticity ensures adequate proppant transport. Fluid efficiency is determined by the polyacrylamide concentration and adjusted to achieve the required fracture geometry. The use of this fluid along with a geomechanical model and pseudo 3D fracturing simulator ensures that the propped fracture remains within the producing sand, with increased effective fracture half-length and conductivity. The polyacrylamide reduces the effective permeability to water and limits potential conning, when the well is produced. Wells completed with frac-packs using the linear fluid produce an average of 1420 bbl/day of fluid with 20% water-cut. The fluid efficiency during the treatments varies between 30% and 15% as a function of permeability. Offset conventionally gravel packed wells with a lower bottom hole flowing pressure (BHFP) average 980 bbl/day of fluid with 60% water-cut. Frac-packs, using an efficient linear fluid together with a geomechanical model and a pseudo 3D fracturing simulator have greatly improved the economics of producing these highly permeable reservoirs—maximizing production and recoverable reserves, while minimizing water production.

In Colombia, relative permeability modifiers (RPMs) are often included in fracturing fluids to limit water production in wet producers. However, the results of their application are mixed. Since many reservoirs have an oil/water contact, or are close to an oil/water contact with poorly defined barriers, the fracture propagates into the water with minimal leakoff of the RPM into the fracture faces. In theory, the RPM polymer present in the interstitial water of the fracturing fluid leaks off into the fracture faces, as the hydraulic fracture propagates. For this to occur requires an inefficient fluid with high fluid loss. However, the properties of RPM fracturing fluids are similar to those of conventional fracturing fluids, highly viscous with leakoff control to ensure adequate fracture geometry and proppant placement. These properties favour vertical height growth of the hydraulic fracture and limit RPM leakoff into the fracture faces. These limitations led to the development of a new fluid and placement techniques, with the objective of increasing the success rate of hydraulic fracturing in wet producers. A linear fluid comprised of polyacrylamide and polysaccharide polymers with a viscosity enhancer. The viscosity of which can be adjusted between 100 and 200 cp at 100 sec-1 over a wide range of temperatures. The relatively low viscosity of the fluid aids in limiting the net pressure and the risk of fracture height growth, in formations with low stress profiles. The addition of fibers provides a mechanical means to suspend and transport proppant, when deemed necessary. Hence, high fluid viscosity is no longer required for efficient proppant transport. By adjusting the ratio and concentration of the polymers, it is possible to independently adjust the viscosity and leakoff control of the fluid as a function of the formation permeability and stress profile. Doing so ensures that the desired fracture geometry is achieved while ensuring adequate leakoff to treat the fracture faces. A fracturing campaign using this newly developed fluid in a mature field in Colombia resulted in an incremental oil production of 12%, while decreasing the water cut by 13%. This demonstrated that reservoirs that were not previously considered candidates for hydraulic fracturing can now be treated without increasing the water/oil ratio (WOR). The use of this fluid, along with a new treatment design methodology, makes it possible to hydraulically fracture reservoirs with, or close to, an oil/water contact. This effectively extends the life of mature fields that are approaching their economic limits.