Drilling in deeper waters calls for more advanced technology. Mark R. Luyster provides an overview of recent fluid advances for the completion phase of deepwater projects.
The industry has evolved in the last decade to further drilling and completion fluids that can attain the required density and integrity for deepwater Gulf of Mexico projects. However, the desired parameters or objectives for such systems breach the density and environmental limits, and challenge the industry to develop fluid systems that ultimately reduce the risk of failure. While proven technology reduces risk, the following article includes a few potential advances with respect to the selection of the required fluid systems and additives for these deepwater prospects, which will also require greater volumes during their development phase.
Fig. 1 - Water depths greater than 4600ft. Source: BSEE.
Data from the US Bureau of Safety and Environmental Enforcement (BSEE) from 1990 to present shows a relative increase in the number of discoveries between 1998-2002 (Fig. 1), approximately 32 per year while discoveries after 2002-2010 range from 8-19 or 12 per year.BSEE’s data shows a marked decrease in annual discoveries after 2010 (the year Deepwater Horizon happened), four per year. However, BSEE’s data also shows a marked increase for the water depth of these discoveries nearly 1000ft for each of the aforementioned periods starting with 1998-2002. If the same data is normalized for discoveries in water greater than 4600ft (Fig. 2) there is not only a relative increase as expected but all the discoveries for the period 2011-2013 are 100% of this baseline as they represent water depths from 5440-8553ft. It follows that the subsequent appraisal and development wells from 2003-2010 and the near recent discoveries will require proven and new technology to develop and advance the infrastructure, drilling and completion phases. These phases may well require technology that has not been devised, which contrasts with proven technology that serves to reduce risk.
Fig. 2 - Water depths greater than 4600ft. Baseline established using deepest TLP, Magnolia-ConocoPhillips. Source: BSEE.
During the period between 2003-2010, the Gulf of Mexico realized exploration drilling, appraisal and development in water as deep as approximately 9575ft. Some of these prospects exhibited potential hydrocarbons/reserves estimated greater than 6 billion boe and operators projected field life up to 40 years. In the last few years, some of these prospects are now realizing initial production while several are pre-planning for their development phase. One area of technology that will play a role to successfully complete these prospects is the required fluids and the additives and products that are used to formulate these fluids; also referred to as systems. Specifically the systems required to drill and complete in the target reservoirs.
Several discoveries from the period 2003-2010 are now either advanced with respect to planning for first oil or realized first oil with one or more completions. Recent reports show more than 40 prospects that may realize first oil in the next few years. The maximum measured depth to attain the target reservoir for the appraisal and/or development wells approaches 32,000ft. These target reservoirs range in age from lower Miocene to Eocene-Paleocene to Upper Jurassic or approximately 33-65 million years to 160 million years for the latter. The reservoir temperature for the Miocene can exceed 200oF while the Eocene-Paleocene reservoirs can approach 250-270oF and the Upper Jurassic over 300oF. The uncompleted reservoir pressures for the Miocene prospects may exceed 20,000psi while the Eocene-Paleocene can exceed 22,000psi. Thus the equivalent density for these reservoirs range up to 14.5 lb/gal whereby a required drilling or completion fluid approximates 15.5 lb/gal. These reservoir parameters dictate a need for drilling and completion fluids (and their associated additives) with relatively greater density and superior integrity to reduce the risk of failure in these deeper prospects. Their failure can result in extended non-productive time and subsequent precipitous costs for apparent reasons.
Environmentally benign drilling and completion fluids and any associated additives are primary to reduce risk in the event of unanticipated spills. With the mandate of utilizing the safety data sheet format (full compliance by June, 2016) versus the previous material safety data sheet a more uniform/identification of the substance/mixture is required. This simplicity of transparency should assist with the planning/decision process. The use of non-chloride brine as well as eliminating chloride from the internal phase of an oil-based fluid is another step towards a more benign fluid. Biodegradation of cuttings produced from oil-based fluids has potential to reduce impact and disposal costs when a synthetic biodegradable external phase is used. This is yet another advancement that can reduce the impact on the environment, land and sea.
However, when one considers the density requirements for these deepwater prospects, especially the completion phase, a very short list of commercial brines: calcium bromide, zinc bromide and formates (K, Na, and Cs) are available. To further, when one considers the relative lack of Gulf of Mexico infrastructure (e.g., dedicated tanks, lines, etc.) and the ability to supply formates at the anticipated required volumes, the list is even shorter. And considering that zinc is a priority pollutant the use of calcium bromide may be the more prudent choice.
For the drilling phase, the use of calcium bromide as a base for a fluid system to drill the target reservoir is well documented (Horton, SPE68965, 2001). However, if incorporated as the internal phase of an oil-based system there are potentially more problems (e.g., gelation) than benefits (e.g., density). The combination of calcium bromide brine and non-barite weighting agents may provide a relatively higher density drilling system that is relatively benign to the environment for these deepwater prospects. In addition, the use of an oil-base system to drill the target reservoir alleges professed damage mechanisms, which include barite to attain the required density and the use of clay for viscosity as well as emulsifiers and wetting agents. However, recent advances may well alleviate these concerns. These include:
- High internal phase ratio (HIPR) oil-base systems. These systems use a unique emulsifier to attain oil-water ratios as low as 20:80 (Fig. 3). At this oil-to-brine ratio a greater volume of divalent brine, which is compatible, comprises the internal phase thus this brine mass replaces a portion of the solids mass, which extends the maximum density (Lim, AADE, 2011). In addition, these systems are stable to temperatures above 300oF.
- Organophilic clay-free and lignite-free oil-based systems can mitigate damage as well as allow for more control of mitigating the ECD.
Fig. 3 – Digital images compare aqueous droplets in the oil continuous phase for a conventional 70/30 OWR (left) versus an invert emulsion HIPR 30/70 OWR (right). The HIPR emulsion provides a more uniform and compact invert emulsion with smaller droplets even at 70% v/v brine. Photo from SPE Paper 144131.
The modeling of bridging solids for a fluid system (drilling or fluid loss pill) used to effectively seal the target reservoir thus reducing losses of whole fluid and/or filtrate is well documented (Dick, SPE58793, 2000 and Chellappah, SPE151636, 2012). These solids are typically barite and calcium carbonate. The technique to model and confirm a bridging solids blend can, in part, strengthen the wellbore and alleviate pipe sticking and losses. However, the key is to manage these solids and their size distribution while drilling to the target depth.
In addition, selected solids can be added as background material to reduce losses and/or strengthen the formation while sealing induced or inherent fractures. A proactive plan is best versus reactive as addition of solids with no prior planning can cause additional problems and even invoke reservoir damage. While these typical bridging solids are available in a variety of grades there are relatively new materials that may provide advantages for these deepwater prospects:
Bridging solids with a greater specific gravity than calcium carbonate can be incorporated in a fluid system. For example, magnesium oxide or complexes of manganese oxide thereby increasing the maximum density of the system.
Bridging solids can be incorporated that reduce rheological properties, such as micronized or ultra-fine barite or calcium carbonate (versus API barite) whereby the ECD of the fluid system is reduced thus the maximum density is essentially extended. The particle size distribution of these types of solids helps, in part, to alleviate sag.
Fig. 4 – Hydrocarbon soluble solids.
Bridging solids that are hydrocarbon-soluble (Fig. 4) can be incorporated into a brine-based drilling system that eventually incorporates into the residual filtercake and then dissolve when the well is initially produced. The hydrocarbons from the reservoir provide the mechanism to partially-completely dissolve these solids. This approach may alleviate treatments used to remove the residual filtercake or costly post stimulation treatments to remove near wellbore damage.
Concurrent with the potential of unanticipated or uncontrollable losses while drilling or running casing; fluid loss pills are available and can be formulated to a desired texture (e.g., soft to rigid) or density (up to 20 lb/gal) and the ability to control the set time provides flexibility during the drilling and completion operations. These cross-linked pills can set in relatively low temperatures (approx. 32oF) and high temperatures (approx. 300oF).
High temperatures can invoke settling of solids as the designed fluid systems viscosity degrades. The often unanticipated degradation whereby the inherent and drilled solids can no longer suspend results in the accumulation of beds that interfere when drilling and running drillpipe. These beds, if not removed, can potentially plug the lower completion assembly (e.g., sand control screen) when running to target depth. What planning teams may request are longer test periods for simulating static and dynamic conditions in the wellbore to confirm a fluid systems’ integrity. There are several mechanisms available to mitigate viscosity degradation, however, some must be carefully addressed as they can impact other desired parameters. For brine-based systems, synthetic viscosifiers are one option; however, these may impact formation damage. Wellbore temperature changes can also influence a fluids viscosity such that it is too viscous. Systems, especially oil-based, can be optimized to maintain viscosity through the temperature changes from surface to seafloor to the bottom hole whereby a flat rheology profile is maintained to mitigate fluctuations during dynamic and static conditions. This alleviates pressure spikes and progressive gels and aids in controlling the equivalent circulating density (ECD).
An appropriate fluid density will promote a mechanically stable wellbore when drilling encounters “soft” shale rock however reactive shale minerals can impart a chemically unstable wellbore. In the case of the latter the proper choice of base brine and/or additives can help alleviate. Upfront planning that includes testing, when whole core is available, for worst-case static periods can confirm the effectiveness of needed additives. However, shale rock can be different from area to area thus a fluid system may require customizing. Soluble additives such as amine based or nanoparticles may provide sufficient inhibition in some shales. In some wells/areas the proper choice of the water activity of the brine alone can provide sufficient inhibition; however, this also limits density and unanticipated changes to the working density.
While oil-based fluids are readily lubricious due to their external phase, lubricant additives for brine-based fluids can reduce their friction nearly equivalent to oil-based while mitigating cheese and grease effects that are common due to the incorporation of fine solids, temperature and shear.
Products that are used to maintain oil-based drilling fluids properties are typically added in the field as a liquid. Some of these additives are now available as solids and this may reduce the volume required to transport, store and even reduce the number of lifts required to transfer products to a rig/platform.
Dual gradient drilling could erase the effect of water depth on offshore drilling and enable operators to reach reservoirs 40,000ft below the sea floor. This technique is similar to managed-pressure drilling and uses seawater density fluid in place of the drilling fluid that would ordinarily flow through a riser while using a denser drilling fluid at the bottom of the well to maintain bottom-hole pressure.
Mark R. Luyster is vice president of technology development for TBC-Brinadd, LLC, of Texas United Chemical Co. He worked for Chevron Production Co. for 13 years before assuming project and lab manager positions with MI-SWACO (a Schlumberger company). During this period he worked in China, Angola, Equatorial Guinea, East Canada, South America, Gulf of Mexico and Alaska.
He served as global technical service manager for the completions segment for the last six years before assuming his position with TBC-Brinadd. Luyster has invented or co-invented nine US patents and has 16 applications pending that involve breakers, fluid treatments, viscosified agents, chelates, invert emulsions and delay mechanisms. He holds a B.S. in geology from the University of Akron.