Hybrid Sand-Consolidation Fluid Offers Versatility in Treatment of Shallow Reservoirs
In this paper, a new type of sand-consolidation low-viscous binding material, based on a combination of inorganic and organic components, is presented.
The Tunu giant gas field is in the Mahakam region of the South China Sea. Because of the maturity of the field, the producing layer has moved from the deep zone of consolidated sand into the shallow zone of unconsolidated sand. Hydrocarbon production from the shallow zone is unmanageable without primary sand control downhole. In this paper, a new type of sand-consolidation low-viscous binding material, based on a combination of inorganic and organic components, is presented.
Tunu produces almost 40% of total gas production in the Mahakam region. Hundreds of wells have been drilled in the field. Its primary-zone reservoirs are between 2000 and 5000 m true vertical depth (TVD) and typically consist of medium to fine sandstone with strong consolidation and high porosity. Above the primary zone, between 1500 and 2000 m TVD, is the Intra Beta section, with high porosity and sufficient consolidation. In the top layer of the field, shallow reservoirs, above 1500 m TVD, are typically poorly consolidated, with high porosity (28%) and permeability (greater than 1 darcy). Tunu’s shallow zone is an unconsolidated zone that requires sand control; types that have been used include gravel pack, stand-alone screen, and sand consolidation. Sand consolidation can be a challenging option because of the difficulty in finding a balance between compressive strength and regained permeability after treatment.
After the first laboratory-testing phase, detailed in the complete paper, showed promising results, the decision to perform field trials on five wells was validated. Wells in Tunu are typically completed using 3.5- or 4.5-in. tubingless completion inside 7- or 9⅝-in. casing. A coiled-tubing (CT) unit was chosen for pumping into the target reservoir.
First Campaign (2012–2013). The primary objective of the first campaign was to acquire experience with the composite binding material in the field without taking the risk of plugging the wells. Therefore, a large amount [6 pore volumes (PV)] of overflush was used. Several tests and subsequent adjustments were developed to tailor the product to actual field conditions. The first campaign began in October 2012 and ended in July 2013 after treatment on five wells.
On the basis of laboratory test results, the treatment comprises the following steps:
- Activation of binding material by dissolving the initiator
- Injection of preflush fluid (0.75-fold binding material volume)
- Injection of the binding system, followed by a small pill of spacer (maximum 0.5 bbl of preflush)
- Post-flushing or overflushing (six-fold binding material volume for first campaign)
For the field application, several safety procedures were implemented. The mixing step was rigorously monitored because of the flammability of the binding system. A carbon dioxide (CO2) blanketing system was connected to the tote tank before the addition of the activator to the binder (Fig. 1). Fire extinguishers were present in the mixing area; a firefighting vessel was placed on standby. Grounding also played an important role in preparation.
Well Preparation. Wellbore fluids were displaced with filtered diesel. Perforation was performed on the reservoir target. Meanwhile, the preflush was premixed and chemicals loaded onto the barge for transfer to the well location.
The primary job preparation consisted of the following steps:
- The CT was pickled and then flushed to diesel; friction pressures were recorded.
- The blowout preventer was rigged up along with the injector head.
- A diesel friction test was performed during the spooling of the CT at surface.
- CT was run in hole with the packer bottomhole assembly (BHA); the packer was set above perforation target.
- A injectivity test was performed through the CT with diesel.
- When sufficient injectivity was reached, the brine overflush was mixed and brine filtering was performed.
- Activator was added to the binding material.
The squeeze treatment consists of preflush, application of binder and spacer fluids, brine overflush, and diesel displacement. When pressure stabilized, the packer was unset and the CT was pulled out of the hole. The well was left shut in for 2 days before well cleanup was performed using a well-testing unit.
During CT operations, a bottomhole gauge was installed on the CT packer BHA to evaluate bottomhole response. After finishing the treatment, a comparison of surface and bottomhole readings was recorded.
For an initial series of field applications with a new product, the results were satisfactory, even if not all applications were successful. The main objective was fulfilled: No well was plugged, and some successful cases were achieved.
Proof of principle was achieved with three successful treatments of wells producing free of sand.
Second Campaign (2014). In June 2014, the second campaign was launched with a new treatment design that reduced post-flush volume to 1.5 PV, a parameter validated by laboratory experiments, in order to increase the residual amount of binder in the pores, improve consolidation strength, and avoid any kind of sand production. The formulation of the product was also modified slightly with an additive promoting adhesion to the sand surface, which also led to increased reproducibility in the laboratory trials. The other operation procedures remained the same as those of the first campaign.
The results of the second campaign showed good consolidation with the composite binding material; no sand was produced when 2 ft of formation around the casing was treated. However, production rates were lower than expected and the reservoirs were considered to be plugged after only a few weeks. Nevertheless, the reperforation of the reservoirs was successful, leading to stable production without sand for several months. The success of reperforation without sand production shows the homogeneous infiltration of the product into the formation, as well as the good consolidation achieved with the hybrid material.
From the results of the second campaign, it was concluded that 1.5-PV overflush may represent a minimum; this amount, therefore, was increased in the third campaign.
Third Campaign (2016). After analysis of the second campaign, the configuration for injection of 3 PV of overflush was investigated in the laboratory exhaustively. Results of these trials showed strong consolidation and sufficient regained permeability obtained by modeling samples placed directly in the near-well region and deeper in the formation. An improved formulation was used for this third phase, including a reactive thinner leading to decreased viscosity for the binding material (6.0–6.5 cp at 20°C).
The results obtained for the third campaign were positive: No sand production was observed, and the gas production rate was at expected levels of approximately 0.8 MMscf/D. The well died because of waterflooding after 30 days of production. These results are all the more satisfactory because no packer was used for this application given the configuration of the well: The fluids were pumped and placed properly by pressurizing the whole well, with no packer up to the surface and a 500-m-high rathole.
- A new composite material for sand consolidation, fully compatible with use of brine and diesel, was applied successfully on several occasions in the field as a primary sand-control treatment.
- No safety incidents were recorded during the eight applications.
- To guarantee that the wells remained unplugged (first campaign) and free of sand production (second campaign), the upper (6 PV) and lower (1.5 PV) limits of overflush amounts were successively tested, with resulting successful rates overall with respect to sand consolidation and gas production.
- Thanks to these first two phases and extensive investigations in the laboratory, a third campaign fully validated the choice of 3-PV overflush. These laboratory tests also demonstrated the strong consolidation obtained after extensive overflush.
- Placement is a key factor for a successful application. Simple use of CT with a CT packer proved to be an efficient method for straightforward placement in a single run.
- In parallel, laboratory work aimed at improving the formulation led to increased consolidation and even lower viscosity. Complete testing and characterization on many different substrates show this product’s potential versatility in formations with high to low permeability, including oil wells. It can be used for a wide range of well parameters.
- The low viscosity of the material also offers the potential for treatment of longer intervals.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189548, “Tunu: From Laboratory to Field Application With a New Hybrid Inorganic/Organic Sand-Consolidation Fluid as Primary Treatment of Shallow Reservoirs,” by J. Andrieu, B. Kutzky, and B.T. Schackmann, Engineered nanoProducts Germany, and A. Mahardhini, SPE, I. Abidiy, SPE, and H.M. Poitrenaud, Total, prepared for the 2018 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 7–9 February. The paper has not been peer reviewed.