SAND CONTROL

Keeping fines in their place to maximize inflow performance

Immobilizing formation fines and enhancing proppant properties keeps formation pore throats, gravel packs and screens clear for hydrocarbon production.

Andy Jordan and Bruce Comeaux, BJ Services

Producing hydrocarbons is by definition disruptive; drilling, completion and production processes upset the equilibrium within a reservoir rock matrix that has formed over hundreds of millions of years. Many of the disruptions impair formation inflow performance, resulting in sub-optimal production.

Prevention is better than cure: The industry is constantly searching for methods to eliminate expensive remedial operations, such as through-tubing completion repairs or full-scale rig re-completions. A variety of new technologies have been developed for implementation during the initial completion to combat problems associated with fines migration.

Clay fines and their swelling and migration are routinely treated with clay stabilizers; however, non-clay fines and potential proppant failure/plugging are often ignored in completion and stimulation planning.

Fit-for-purpose, engineered solutions can minimize inflow performance reduction caused by fines generation, fines migration, plugging of the rock matrix, proppant pack or screens. Depending on formation characteristics, system components might include additives such as fines-stabilization agents, proppant enhancement materials and/or resin-coated proppants.

FINES MIGRATION

Due to their weak nature, most unconsolidated sandstone formations require some type of solids production control. Well screens, often combined with gravel packs or frac-pack treatments, are routine solutions.

Many unconsolidated sandstone reservoirs are also associated with steeper-than-normal production decline due to fines migration. In these formations, fines are typically very loosely bound to the reservoir sand grains. When mobilized, fines may plug the pore throats of the formation, gravel or well screen, Fig. 1.

Fig. 1. A scanning electron microscope image shows fines on the formation matrix; chemical and mechanical effects cause the fines to migrate, blocking pore throats and reducing permeability and production.

This phenomenon has been reported in most of the geographical areas where these rock types are prevalent, especially the Gulf of Mexico, California, the North Sea, the west coast of Africa and Venezuela. Some mineralogical studies in the more recent development areas in India, China and other Asia-Pacific basins also indicate the potential for fines migration.

Mineralogical studies can readily identify a specific formation’s potential for fines migration. Problematic migrating siliceous fines are defined as sub-44-µm solid particles, with further categorization by size (colloidal fines being particles smaller than 2 µm) and by composition (clay materials and non-clay fines such as quartz, feldspar and mica).

Depending upon their size and composition, fines can be mobilized in a variety of ways, generally divided into chemical and mechanical phenomena. Chemical effects weaken the bonds between the fines and the rock matrix. Mechanical effects relate to the drag forces on the particles due to fluid flow within the matrix. Mechanical effects may also be exacerbated due to changes in downhole stresses during production.

Although the mechanism is not totally understood, fines may actually be generated during the completion process as a result of fluid infiltration into the formation. As native reservoir fluids are displaced with completion fluid filtrate, the chemical environment changes, weakening the forces bonding the fines to the matrix. Simultaneously, mechanical forces are introduced as the filtrate flows though the matrix. The velocity and drag forces of the filtrate forced through the rock pores during the sand control/frac pack process are typically an order of magnitude greater than the flow rate during subsequent production. But in many cases drag forces from production alone can be sufficient to cause fines migration, particularly when associated with increasing water breakthrough.

In addition, it has been well-documented that acid stimulation treatments, if not properly engineered, by their nature may release large quantities of fines. Clay stabilization additives are used to minimize potential damage, but when non-clay fines are present, plugging damage from migrating fines is often observed. Fines stabilization additives have long been used to combat this problem.

One particularly successful fines stabilization option has been a Hydrolysable Organosilane Complex (HOC) that forms a non-oil-wetting polysiloxane coating to “link” (by a covalent bond) siliceous particles (clay and non-clay grains and fines), thereby immobilizing small particles. Importantly, the short-chain polysiloxanes do not adversely affect permeability.

ACID TREATMENTS

In a typical acid stimulation example, after treating a well in Bolivia in 2003, the operator recorded four-fold production with a 1/2-in. choke, but the decline rate was high because the Petaca formation was producing fines. Re-stimulating the well with acid and 5 gpt of the fines stabilizer dropped the decline rate and extended continuous production for several months. In a second Petaca formation well, the acid treatment quadrupled the production from 90 to more than 400 bopd, with production continuing at 300 bopd some 70 days later.

In the Gulf of Mexico, a 2003 field-wide study of historical production in a mature field determined that fines migration was significantly contributing to field-wide production declines and the inability to sustain production increases after acid stimulations. The acid treatments were re-engineered using the (clay) fines stabilizer and some acid stimulation best practices (comprising afterflush and preflush of a CO₂ preflush stage, and optimizing the mix of hydrofluoric and hydrochloric acid in the main stage). The result was increased long-term (>10 months in some cases) oil production in the field by more than 150 bopd per well.

Although it has not been quantified how much each design change affected the overall improved outcome, rather than trying to determine which particular re-engineered procedure had the greatest effect, the operator simply continued to apply all of the changes in the stimulation program on each well.

These and other similar acid stimulation experiences suggested that HOCs might be useful for fines stabilization in other problem areas.

LABORATORY TESTING

To verify the efficiency of a HOC fines stabilizer used as one component of a sand control service, a 2% KCl solution was flowed through a synthetic sandstone core while technicians monitored pressure differentials and permeability changes due to fines mobilization. The test was then repeated with an initial treatment of the fines immobilizer.

The first flow test results (without any fines stabilizer) show a marked decrease in core permeability with increasing flowrate. When the flowrate decreases, the permeability remains relatively constant but significantly lower. Over the test period, permeability of the core drops to 47% of the original, indicating fines migration and pore-throat bridging, Fig. 2.

Fig. 2. When KCl is flowed through a synthetic core, permeability drops as flowrate increases, indicating fines migration and pore-throat bridging.

When a synthetic core was pre-treated with a 1% solution of fines stabilizer for the same test, pressure differentials quickly stabilized at each change in flowrate, Fig. 3. Permeability essentially remained constant throughout the test, indicating no problem with fines migration.

Fig. 3. When the KCl solution is flowed with a fines-stabilization agent through a synthetic core, permeability remains constant as flowrate increases.

GULF OF MEXICO RESPONDS

In May 2003, an operator completed a well in the Gulf of Mexico’s Eugene Island field with perforations from about 16,000 to 16,800 ft. The well and others in the area were known to have problems with “floating fines,” which other operators had tried to combat with gravel packs and by controlling production rates. The well appeared to begin to plug off almost immediately, with last production in November 2003 (after about 6 months of production).

In February 2006, the operator side-tracked the well and asked BJ to complete it in the same sand using a frac pack and an engineered treatment with fines stabilization. Some fifteen months later, the well is continuing to flow 3.6 MMcfd, 169 bopd and 43 bwpd without any evidence of sand or fines production.

CALIFORNIA DIATOMS

Meanwhile in California, engineers have found fines control success by using sand control technology in diatomaceous formation fracture treatments. Hydrocarbon-bearing diatomaceous formations are unique because they have high porosity but little permeability; they are also noted for fines migration-related production declines.

In a fracturing project that began in 2001 in the Lost Hills field of California, an operator began completing oil wells in diatomaceous formations, fracturing in two stages with a total of 130,000 lb of 20/40 white sand up to 6 ppg. The first four wells failed almost immediately due to severe formation fines production and proppant flowback. Formation studies found large amounts of detrital quartz in the rock, and it was later discovered that many leases in the area were plagued with fines production issues.

A proposed solution used a sand control system fines stabilization component in a 150-bbl pre-flush of KCl brine before the main fracture treatment. Out of 57 wells treated using this system, only two are producing fines.

PROPPANT PACK

The single most important factor for maximizing production rates and cumulative overall production volume is to maintain a damage-free conduit between the wellbore and the reservoir. Therefore, the ability to place proppant/gravel into a wellbore efficiently and maintain the pack/fracture permeability is of utmost importance.

In hydraulically fractured wells, stress on the proppant initiates at the end of placement as the fracture tries to close but is held open by the proppant grains. This closure stress increases as pressure drops in the wellbore and fracture-the drawdown and pressure depletion used to flow the reservoir fluids. Inevitably, some proppant fails mechanically and breaks into fine particles. Cyclic stress from repeated production followed by shut-ins has also been demonstrated to further compound proppant fines generation and fracture embedment in unconsolidated reservoirs.

Fines from proppant failure and embedment will greatly reduce fracture conductivity and can partially plug annular gravel packs and well screens.

Fines generation from proppant can be significantly reduced with certain materials, especially those that are sized, deformable particles intermixed with conventional proppants, Fig. 4. Upon closure, these particles “cushion” the proppant from damaging stresses. The material essentially adds elasticity to the proppant pack without adversely affecting proppant pack permeability and fracture conductivity. Hence, proppant crushing, embedment and fines generation are reduced, enhancing proppant pack performance under cyclic stress.

Fig. 4. After undergoing 7,000-psi closure stress, a “cushioning” particle is deformed and shows indentations on its surface. This surface flexibility aids in locking proppant in place, increasing the proppants’ resistance to movement.

A recent test for a major international operator measured proppant flowback and failure under extreme conditions expected in high-rate gas wells: the laboratory simulated a pressure gradient of more than 2,200 psi/ft through the proppant packs, exacerbated by pressure surges to simulate stress cycling. The testing compared resin-coated proppant to normal proppant with 10% of this material (an option that would save the customer some $400,000 compared with the specified top-of-the-line resin-coated proppant). Neither proppant pack failed totally, but cumulative production of 2% of the resin-coated proppant suggested it to be susceptible to cyclic loading.

Laboratory and field results suggest that sand control and fines migration mitigation are engineering challenges that can be overcome with proper formation analysis, treatment design and safe execution.

ACKNOWLEDGMENTS

The authors thank BJ engineers John Fontenot, Kimberly Spurlock, Marty Usie, Nabil El-Shaari, Andy Swint and Tony Martin for compiling the data and case histories for this article.