By Chip Hale, BJ Services Company
Deepwater and deep-shelf exploration and development in the Gulf of Mexico continues to gain momentum, and each new extension of water and drilling depth issues the industry new challenges to traditional drilling, completion and production technology. As part of an optimal completion design, sand control technology faces its share of challenges as wells reach further into unconsolidated formations.
Most unconsolidated sandstone formations require solids production control because drilling, completion and production processes upset the equilibrium within a reservoir rock matrix that has formed over hundreds of millions of years. Therefore, well screens, often combined with gravel packs or frac pack treatments, are routine solutions.
Nevertheless, even routine solutions become more complex when they occur in deeper waters and in deeper wells with temperature and pressure conditions far more severe than those experienced in “typical” operations. For example, high-pressure reservoirs tend to mobilize migrating fines, requiring engineered, fit-for-purpose solutions. In addition, higher rig costs drive the search for time-saving devices that can perform multiple tasks in one trip. Finally, as economics drives the proliferation of extended-reach (ER) horizontal wells, engineers must turn to new technologies to ensure efficient gravel packing under many difficult conditions.
Many unconsolidated sandstone reservoirs experience steeper-than-normal production declines due to migration of fines that are very loosely bound to reservoir sand grains. When mobilized, fines may plug pore throats in the formation, gravel or well screen, as is reported in areas such as the Gulf of Mexico, California, the North Sea, the west coast of Africa, and Venezuela. Mineralogical studies suggest this problem may also appear in India, China and other Asia-Pacific basins.
Problematic migrating siliceous fines are solid particles smaller than 44 µm, with further categorization by size (colloidal fines being particles smaller than 2 µm) and composition (clay materials and non-clay fines such as quartz, feldspar and mica). They are mobilized through chemical or 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 matrix fluid flow, which can be exacerbated by changes in downhole stresses during production. In many cases, drag forces from production can cause fines migration, particularly when associated with increasing water breakthrough.
Fit-for-purpose, engineered fines mitigation solutions such as SandChek treatments can minimize inflow performance reduction caused by fines generation, fines migration, and plugging of the rock matrix, proppant pack or screens. Depending on formation characteristics, treatment components might include fines stabilization agents, proppant enhancement materials and/or resin-coated proppants.
For example, in May 2003, an operator completed a well in the Gulf of Mexico Eugene Island field with about 80 ft of productive pay around 16,400 ft. Nearby wells had problems with fines migration and plugging, and this well began to plug off almost immediately, ultimately producing for only about six months. In February 2006, the operator side-tracked the well and asked BJ Services to complete it in the same sand using a frac pack and an engineered SandChek treatment with fines stabilization. Fifteen months later, the well was continuing to flow 3.6 MMscf/D, 169 BOPD and 43 BWPD without evidence of sand or fines production.
BJ has performed some 40 engineered sand control operations with 10 Gulf of Mexico customers in the last two years, including designing completions and pumping gravel and frac packs with appropriate SandChek system components.
MANY ZONES, ONE TRIP
One of the biggest costs associated with completing offshore and complex onshore wells is the time it takes to run or remove a tool from the wellbore. Depending on well depth, tripping time can account for the majority of the overall completion cost. To minimize that tripping time, BJ’s ComPlete family of single-trip completion systems performs all critical completion tasks with a single trip into the wellbore. The latest addition to this technology family is the multi-zone single trip (MST) system.
The ComPlete MST system facilitates gravel- or frac-packed completions across multiple production intervals, again in a single trip. Its design allows complete flexibility in sand placement techniques, including positive, selective isolation of all zones during completion, stimulation and production operations. An operator can even elect to complete some zones and return later to complete others without a rig.
The result is an effective reduction in completion cycle time — and cost — by 20% to 40%. Eliminating one-third of a typical 12-day completion schedule on a multi-zone deepwater well can save an operator as much as $1 million on the total operation cost, even with a conservative $250,000 dayrate for the rig.
The tool’s first commercial applications were in April and May on a pair of two-zone wells in Indonesia, where all components of the MST system performed as designed, including multiple manipulations of the auto-locator, sleeves and valves as planned during the stimulation program. In July, the system was used in a two-zone Gulf of Mexico well.
The system eliminates a number of operational steps compared with traditional multi-zone frac-pack and gravel-pack completions, such as multiple perforating trips; packer plug retrieval runs; multiple gravel pack assembly runs; and stimulation trip runs on workstring.
Benefits to the operator include individual zone isolation while treating; zone isolation after treating; selective access for production; maintain large bore for optimal flow; support large-bore service tools for optimal treating rates; and quicker realization of production initiation.
The system is available for use in 7-in. through 10 ¾-in. casing sizes, with no restrictions on zone length. Individual zones are produced through wire-wrapped production sleeves used as screens below blank pipe and a gravel-pack or frac-pack sleeve with an isolation production packer. Premium screens may also be used in place of the wire wrap if needed. Up to four internal profiles are available with the wire-wrapped production sleeves to provide zonal selectivity for production. After the last zone has been completed, the workstring and service tool are removed from the wellbore, leaving a large-bore, full-open ID completion with selective-flow capability.
Advances in drilling technology are producing record-breaking extended-reach wells, reaching as far as 24,500 ft from a floating installation. As these distance records grow, horizontal open-hole completions longer than 6,500 ft have become commonplace.
Many of these wells are open-hole completions requiring challenging sand management designs. Deepwater ER wells, in particular, are a significant challenge, often exhibiting excessive fluid loss, variations in hole stability and hole geometry, and/or an extremely narrow pressure window between bottomhole pressure and fracture gradient. The narrow pressure window can be a particular concern because high pump rates required for long-distance proppant transport may fracture the formation, causing fluid loss and a sand bridge or early screenout during gravel placement.
The pumping boundaries for open-hole gravel packing are Qmin, the rate at which a sand bridge is likely to form (typically at a dune ratio of 85%), and Qmax, the rate that would result in formation fracturing pressure. In washed-out hole sections and at extreme displacements, Qmin can easily exceed Qmax. Therefore, reducing Qmin is a critical element in designing a long, extended-reach open-hole gravel packing operation. An ideal solution is to utilize the low settling velocities of ultra-lightweight gravels.
Conventional sand control applications use natural sands and manufactured ceramics with 2.65-2.71 specific gravity (sg). For a typical 8 ½-in. open-hole wellbore, the ideal placement rate would be about 9.5 bbl/min, which would generate more than 5,000 psi of friction pressure in a borehole length of 5,000 ft. This is generally well above the formation fracture pressure and would result in an aborted gravel-pack attempt.
Available lightweight gravels can alter the sand control equation because of their specific gravities of 1.75 or less. For example, a gravel of 1.25 sg in the wellbore described above could be pumped at rates of only 3.4 bbl/min with friction pressure around 600 psi — satisfactory operating conditions for a gravel pack.
In fact, the technology works well in practice, as evidenced from results in six wells offshore Brazil and two in the Gulf of Mexico, including one in August.