Comprehensive testing validates deepwater fluid selection
A decade of deepwater experience in the Gulf of Mexico has taught the oil and gas industry a number of expensive lessons about the planning and testing required for successful completions. These lessons have altered the routine testing and evaluation required to properly rank and qualify fluid candidates for use in deepwater production tubulars.
For example, new materials used in deepwater production tubulars and the increasing complexity and cost of deepwater projects, demand greater attention to the design and selection of completion and packer fluids. This requires an integrated approach, from mud displacement through final sand control completion, to optimize fluid compatibility and effectiveness.
Advanced testing regimes provide new levels of information that are critical to pre-planning and evaluating materials and processes for deepwater projects. Recent experiences in planning for a significant deepwater project provide insights into a new paradigm for comprehensive fluid testing and evaluation plus its ultimate value in ensuring a successful completion.
Unexpected lessons
The industry has learned through hard lessons that, under high pressure, completion brine can crystallize above its true crystallization temperature, completely blocking the wellbore. Similarly, gas hydrates can totally block a well and can form at temperatures well above the freezing point of water when high pressure is exerted on a hydrocarbon gas/water mixture.
These adverse situations arise under low mudline temperature and high pressure regimes that are common in deepwater projects. Dramatic reduction in temperature from surface to mudline and increase in temperature from mudline to bottomhole exert sufficient stress to impact fluid selection and require improved displacement technologies.
In addition to routine laboratory tests for fluid compatibilities, it is important to test materials under conditions that are as close as possible to expected actual conditions (formation fluids, rock, temperatures, etc.) to ensure downhole compatibility. Whereas routine testing can analyze fluids at a typical temperature or mixture ratio, a more comprehensive testing paradigm ensures compatibility at the variety of temperature and mixing ratios that the fluids could encounter in the wellbore.
A recent experience in planning completion brine, packer fluid, and other fluids for a deepwater project demonstrates the value of such an advanced testing regime.
Fluid requirements
A deepwater well in 669 m (2,196 ft) water depth in the Gulf of Mexico was expected to produce copious amounts of oil and high-pressure gas. The well had a bottomhole temperature of 84° C (183° F) and a mudline temperature of 4.4° C (40° F). Because of the mudline temperature and water depth, two design criteria were established for the completion brine and packer fluid. The fluids had to have a 1.7° C (35° F) pressure crystallization temperature (PCT) at 10,000 psi and hydrate inhibition at 3° C (38° F) to 9,200 psi, with brief transients to 12,000 psi during BOP testing.
It was also essential that the fluids protect the production tubing from environmental stress corrosion cracking and be compatible with the reservoir rock, formation water, produced hydrocarbons, and other selected fluids.
Two types of completion brines proved to be viable candidates: cesium-, potassium-, and sodium-based formate brines and zinc-, calcium-, and sodium-based bromide and chloride brines. Initial fluid choices were made based on their compatibility with formation water.
The amount of formation water available for compatibility testing with the candidate completion brines and packer fluids was extremely limited. Therefore, the bulk of compatibility testing was conducted with synthetic water analogous to the formation water based on chemical analysis. Final qualification testing was conducted with the limited amount of formation water available.
For this detailed study, fluid was tested in ratios of 25/75, 50/50 and 75/25 at ambient and bottomhole temperatures. The samples were examined for solid precipitates.
Compatibility with the formation water has been historically determined by mixing the selected brines with synthetic or actual formation water at ambient conditions and/or at favorable water/brine ratios (e.g., only at 95/5). This detailed testing, however, tested the fluids in ratios of 25/75, 50/50 and 75/25 at ambient and bottomhole temperatures. Then the samples were examined for solid precipitates. The advantages of this more thorough analysis became apparent; it is highly recommended for all deepwater and critical projects.
Two samples of a 15.4 lb/gal cesium potassium formate were tested. The first sample created significant precipitation when mixed with the synthetic water in most ratios mixed at ambient temperature and in all ratios mixed at 82° C (180° F). A second sample with less buffer and lower pH remained clear at 21° C (70° F) but only at a ratio of 75/25 water/brine. When heated to 82° C (180° F), however, the mixtures at ratios of 50/50 and 25/75 water/brine dissolved to form clear solutions, but the 75/25 water/brine mixture generated a significant amount of precipitate. The second sample was also tested with the actual formation water, which produced significant amounts of precipitate at all ratios tested with less than 75% formate brine, at both 21° C (70° F) and 82° C (180° F).
In contrast, the 15.6 lb/gal zinc-based completion brine was found to be completely compatible with both the synthetic water and formation water at all ratios.
Based on these findings, the zinc-based brine was selected for the working completion brine, and an 11.5 lb/gal sodium bromide-based fluid was selected as the packer fluid for this project.
Clay sensitivities
Small core samples underwent mineralogical evaluation using x-ray diffraction (XRD) analysis, thin-section examination, and environmental scanning electron microscopy (ESEM).
The project’s main 45.7-m (150-ft) zone consists of an upper silt/shale interval, two upper sand intervals (1A and 1B), a lower shale interval, and a lower sandstone interval. Capillary suction time (CST) testing verified that the zone was highly sensitive to freshwater and completely disaggregates in low-salinity fluids.
CST results indicated that both the silt/shale and shale samples were sensitive to water, but less sensitive to conventional brines. Potassium chloride (KCl) was observed to reduce water sensitivity, even when added to the zinc-based brine.
XRD analysis highlighted the rock’s expandable illite-smectite clays and potentially migrating zeolites. The presence of the clays confirmed the rock’s water-sensitivity. ESEM pinpointed the locations of these clays and minerals in the pore channels, indicating that the working completion brine would easily contact them. Therefore, 3% KCl was added to the zinc-based completion brine for additional clay control.
Hydrates and crystallization
Highly concentrated salt solutions (such as high-density completion brines) are efficient thermodynamic hydrate inhibitors and typically require no additional additives. The 15.6 lb/gal zinc-based brine with 3% KCl was qualified by simulation to have a hydrate equilibrium pressure well above the 9,200 psi maximum shut-in pressure at the 3° C (38° F) subsea tree temperature. Its PCT at 10,000 psi was well below the 1.7° C (35° F) requirement.
For the packer fluid, the standard 11.5 lb/gal sodium bromide did not sufficiently inhibit hydrate formation. Simulation suggested that the packer fluid should contain at least 18% and preferably 25% of a low-molecular-weight alcohol to improve its hydrate inhibition characteristics. This formulation also qualified under the PCT requirement.
Oil compatibility
To determine compatibility of the selected completion brine candidate with formation hydrocarbons downhole, the brine and hydrocarbon were mixed at a 50/50 ratio at bottomhole temperatures. The combined sample was shaken vigorously to facilitate emulsion formation, then the sample was stabilized at temperature and periodically shaken again. The heat-aged, shaken samples were then observed static for 15 min.
In this test, the oil completely broke from the zinc-based brine with a clean, sharp interface within 15 min. An industry standard non-emulsifier was also tested at reservoir temperature, and it produced a clean sharp break after just five minutes. An optimized amount was added to the completion fluid system as a precaution in case the crude oil in place was different from the tested sample.
Such testing had been conducted at ambient temperature and an oil/brine ratio 50/50 for many years. Advantages of the heat-aged procedure are readily apparent when testing certain crude oils, and the improved paradigm is recommended for all deepwater and critical projects.
Prepared for problems
Various fluids are considered for injection into the production stream for deepwater projects. For example, a well might require injections of methanol, low-dose hydrate inhibitors, anti-scaling agents, or organic deposition inhibitors. Added chemicals can interact with other wellbore fluids. Their compatibility should be known beforehand so contingency plans can be formulated well in advance.
The simple fluid/fluid tests historically conducted to assess such fluid interactions fall short of providing adequate information for proper deepwater project planning. In this case, the packer fluid brine was tested with an organic deposition inhibitor using a more comprehensive testing regime at about 1.7° C (35° F) at the mudline, 21° C (70° F) ambient temperature, and 82° C (180° F) bottomhole temperature, with fluid-to-brine ratios of 75/25, 50/50, and 25/75.
At 1.7° C (35° F ) and 21° C (70° F), the fluids remained clear and compatible (but not miscible). When heated to 82° C (180° F), the brine layer remained essentially clear, but an emulsion formed in the organic layer. Some small amount of brine could have been incorporated into the emulsion, but the emulsion remained fluid.
A more complicated picture resulted when similar tests considered compatibility of the organic deposition inhibitor with the control line fluid. In this case, emulsions were observed even in the brine phase.
The packer fluid was tested with control line fluids using the same comprehensive testing. As anticipated from the chemistry of these systems, the 11.5 lb/gal sodium bromide packer fluid was completely compatible at all temperatures and in all ratios.
Effects on tubulars
Corrosion resistant alloy (CRA) production tubing has failed in the field due to stress corrosion cracking (SCC). It has, therefore, become standard practice to determine the vulnerability of CRA tubulars, especially high-strength CRA tubulars, to completion brines and packer fluids.
Weight-loss corrosion testing on standard metal coupons has been routine for some time, but C-ring testing of actual tubulars for a specific project has become the new additional paradigm for evaluating completion brine for deepwater applications. The C-ring test procedures, machining practices, and calculations are based on NACE Standard TM0177-96, Method C.
Based on historic data and laboratory testing at 82° C (180° F) with actual project tubulars (HP1 13Cr 110YS) for 14 days, the inhibited 15.6 lb/gal zinc-based brine with 3% KCl resulted in an “as new” coupon without pitting, cracking, or corrosion. Furthermore, a seven-day weight-loss test performed with C-4130 (representing casing steel) in the zinc-based brine resulted in a uniform corrosion rate of only 2.5 mpy (mils per year).
The sodium bromide packer fluid had been qualified previously and needed no additional testing.
Core-flow analysis
Flow testing of core plugs is the final step in confirming that a selected fluid system will not damage the formation. Core flow analysis has been routine for many years for all types of wells. Its importance for successful completion in a deepwater environment cannot be overstated.
For this application, core flow testing was done with completion brine and frac fluid candidates. The time between cutting the cores and start of the rig site completion process was extremely short, so the fresh state cores were tested as received.
Five flow tests, one on the 1A sand and four on the 1B sand, indicated that minimal damage resulted when the completion brine and proposed frac pack fluid flowed through these cores. Both the completion brine and the frac fluid were therefore qualified for use in this deepwater project.
Acceptable results were also obtained from the sequential treatment of one core as it would occur in the field: completion brine to fluid loss control pills to cleanup acid to frac fluid.
The project was completed on time and on budget and met the deliverability requirements.
Time for testing
The paradigm for a deepwater project includes a comprehensive suite of testing and evaluation at a variety of appropriate temperature and pressure conditions:
- Pressure crystallization of completion brine
- Gas hydrate inhibition
- Stress corrosion cracking studies
- Brine compatibility with formation water, formation oil, control line fluids, injection fluids and other planned (or potential) workover fluids
- Brine compatibility with formation rock.
This level of comprehensive testing for deepwater projects requires careful planning, scheduling, and coordinating. Many individuals with unique skills are involved, and testing must be scheduled into their workload. In addition, although many of the tests are not complicated, they often require specialized equipment. Some tests might require three to four weeks to conduct, plus set-up, break-down and analysis time. Furthermore, testing can produce unexpected results that even further extend testing, analysis, and the decision-making process.
