Formation damage

Test Methodology Optimizes Selection of Fluids for Gasfield Development

For the development of the Dvalin high-pressure/high-temperature (HP/HT) gas field in the Norwegian Sea, a completion scheme using standalone screens is planned.


For the development of the Dvalin high-pressure/high-temperature (HP/HT) gas field in the Norwegian Sea, a completion scheme using standalone screens is planned. To secure maximum cleanup and productivity, even after long-term suspension, comprehensive laboratory testing was performed to evaluate specific properties from drilling and completion fluids at downhole conditions. The complete paper details the results of all test phases. With the test methodology, several proposed mud-system candidates were disqualified at an early stage, thus saving time and cost for subsequent formation-damage testing and complementary analytics.


Formation damage is believed to have caused difficulties in modular-dynamic-tester sampling in the high-permeability zone of Dvalin West. The damage mechanism has been investigated in a study that revealed both fluid systems to have good fluid-loss-control properties, as observed in drilling operations. However, both systems showed damage potential. The extent of damage is more pronounced in Dvalin West.

The field-development plan calls for four producing wells to be drilled (two in each structure). Prevention or, realistically speaking, minimization of impaired production as a result of formation damage has been identified as a priority. A completion scheme with standalone screens requires additional specific properties from drilling and completion fluids at downhole conditions. The production facilities will be commissioned after the completion of drilling, and there are no provisions for handling cleanup flow through pipeline and topsides. Thus, all wells will be cleaned up to a temporary test plant onboard the drilling rig. The lag time between drilling the wells and cleaning them will be 2–3 weeks, underlining the necessity of a drilling mud that is stable over a significant period of time while retaining inherent mobility.

Six reservoir drill-in fluids (water- and oil-based) were proposed by different vendors, and samples thereof and the corresponding screen fluids (if available) were provided. The systematic test program consisted of a sequence of four test phases, where only successful fluids went to the next phase (Fig. 1). A description and application of equipment and processes is provided in the complete paper.

Fig. 1—Schematic of the selection and optimization test phases.

Data and Results

Phase I. The first test phase comprised a set of simple screening laboratory tests. The best-in-class drilling and completion fluids from the study were then tested with regard to formation damage (return permeability tests). Tested qualities included density, particle size distribution, rheology, mobility, settling, emulsion stability, HP/HT filtration and rheology, compatibility, and production-screen testing. As detailed in the complete paper, many of the fluids demonstrated acceptable or good performance in many of these aspects; nevertheless, on the basis of observations during Phase I, two out of six fluid systems could already be excluded as unstable for the application (Drilling Fluids 1 and 6).

Phase II. For this test phase, the provided new batches of the four eligible remaining mud samples were characterized again regarding their basic properties to ensure that the samples were equivalent to the fluids assessed in the first round as well to any upcoming batches in the future. Additionally, fluid properties after long-term aging (14 days at 160°C) were characterized for the first time. Whenever applicable, current properties were compared with previously reported results. Furthermore, formation-damage tests on outcrop material with properties comparable to those of the Garn formation were performed.

Severe signs of temperature instability upon the static aging period were observed for Drilling Fluids 2 and 3. Only Drilling Fluid 4 exhibited an excellent temperature stability under the static aging conditions, whereas Drilling Fluid 3 almost completely lost its viscosity, most likely from degradation of the polymers.

Drilling Fluid 2 was too viscous after aging to be filtrated. Drilling Fluid 3 did not possess filtration-control properties anymore, thus exhibiting an infinite filtration volume combined with an undefined filter-cake thickness. Formation damage was considered severe to mild. In all fluids except Drilling Fluid 3, if the near-wellbore area could be cleaned up or bypassed, damage would be considered mild. On the basis of only return-permeability results, Drilling Fluid 4 consistently performed better on both the medium- and super-high-permeability lithology.

Drilling Fluid 3 saw the least improvement in permeability after the removal of the external operational fluid cake and hardware compared with other sequences. This suggested that the formate-based Drilling Fluid 3 caused the least barrier to flow at the interface of the operational fluid cake and the formation. Because of inadequate temperature stability and observed severe formation damage in Phase II, Drilling Fluid 3 was disqualified from further testing.

Phase III. For this phase, new ­batches of the three remaining eligible mud samples were quality-checked as delivered before the formation-damage and return-permeability tests were conducted. If available, the properties were compared with those of the previous batches. In this phase, formation-damage tests were conducted on actual reservoir rock core samples (Garn) covering medium and low permeability.

Drilling Fluid 2 and its screen fluid had slightly lower emulsion stabilities compared with results in Phases I and II but were still regarded as being within specifications. With regard to production-screen testing, only the drilling/screen fluid pair of Drilling Fluid 4 fully passed the screen. The time for full outflow was between 3 and 4 seconds, identical to results from Phase II. Also, Screen Fluid 2 passed the screen after aging 4 seconds, but its counterpart, Drilling Fluid 2, only yielded a relatively slow outflow, with fluid remaining inside the cell. This is in accordance with observations from Phase 1, where this drilling-fluid system also caused a plugging of the screen after 1 second.

On the basis of the overall rating in Phase III, Drilling Fluid 2 was disqualified because the low performance (plugging) of the statically aged fluid (14 days at 160°C) in the production-screen tester. Drilling Fluid 4 was chosen for its long-term stability, superior HP/HT rheology, and screen compatibility, and it exhibited a return permeability of greater than 80%. At this point, Drilling Fluid 5 was considered a backup option.

Phase IV. To this point, long-term stability was only assessed by aging the fluid samples statically at 160°C up to 14 days. For operational reasons, it was valuable to know the stability for even longer periods; therefore, selected mud properties after static aging for 1 month also were evaluated and compared for Drilling Fluids 4 and 5. Whereas Drilling Fluid 4 remained mobile after 1 month of aging despite an increased rheology profile, Drilling Fluid 5 became too viscous and immobile for further testing. As a consequence, Drilling Fluid 5 (both drilling and screen fluid) was disqualified.

Phase V (Optimization). In this phase, the detailed formulation of the selected fluid (Drilling Fluid 4) was varied systematically and the effect on the return permeability recorded. The objective was to minimize the formation damage further, thus increasing return permeability.

The final such variation for Drilling Fluid 4 (Fluid 4.4) exhibited the highest return permeability at the first two stages of the test sequence (i.e., 74% after drawdown and 88% after removal of hardware and operational fluids). Because it represents the least impairment of the reservoir, this is the fluid formulation nominated as the reservoir drill-in fluid for the Dvalin field development. Fluid 4.4 also will be recommended for Dvalin East wells, especially with regard to the suspension and bridging agent types and concentrations as well as reduced primary emulsifier concentration.

For all fluids, return-permeability results after spindown are greater than 90%, indicating that a significant cause of damage is the result of either retained filtrate or another cause (e.g., fines migration). However, this limited damage may be considered acceptable.


The internal testing of drilling-fluid systems proposed by different vendors as a first stage allowed for live experience of the fluids and assessment of key properties under operating conditions. Normally, a service company has too-limited capabilities to run extended times for aging.

With the proposed methodology, several mud-system candidates were disqualified at an early stage, thus saving time and cost for subsequent formation-damage testing and complementary analytics. The test series allowed selection of one mud and completion-fluid system on the basis of long-term stability, superior HP/HT rheology, and screen compatibility. Furthermore, the testing allowed for further optimization of the optimal product in cooperation with the vendor, thus maximizing future productivity of the production wells.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195601, “Systematic Selection of Drill-In and Completion Fluids for Development of the Dvalin High-Temperature Gas Field,” by Oliver Czuprat, SPE, Bjorn Olav Dahle, and Ulf Dehmel, DEA, et al., prepared for the 2019 SPE Norway One Day Seminar, Bergen, Norway, 14 May. The paper has not been peer reviewed.