Systematic Selection of Drill-In and Completion Fluids for Development of the Dvalin HT Gas Field

Czuprat, Oliver; Dahle, Bjorn Olav; Dehmel, Ulf; Ritschel, Robert; Storhaug, Jens; Adrian, Thomas E.; Patey, Ian

doi:10.2118/195601-ms

Cited by 7 publications

(1 citation statement)

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“…The HTA completion fluid consisted of formate brine, 3 wt.% HTA, and 1 wt.% CA101. The results showed that the return permeabilities under static/dynamic conditions were 84.7% and 87.95%, respectively, indicating that the chelating acid completion fluid effectively removed the temporary plugging layer [ 14 , 37 ]. Therefore, a plugging layer formed by the acid-soluble temporary plugging agent, polymer, and starch, can be further removed by acidic completion fluid or subsequent acidification, and the productivity can be fully released.…”

Section: Resultsmentioning

confidence: 99%

Formation-Damage Mechanism and Gel-Breaker-Free Drill-In Fluid for Carbonate Reservoir

Fang

Zhao

Sun

et al. 2022

Gels

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Abundant oil and gas reserves have been proved in carbonates, but formation damage affects their production. In this study, the characteristics and formation-damage mechanism of the carbonate reservoir formation of the MS Oilfield in the Middle East were analyzed—utilizing X-ray diffraction, a scanning electron microscope, slice identification, and mercury intrusion—and technical measures for preventing formation damage were proposed. An ‘improved ideal filling for temporary plugging’ theory was introduced, to design the particle size distribution of acid-soluble temporary plugging agents; a water-based drill-in fluid, which did not require gel-breaker treatment, was formed, and the properties of the drill-in fluid were tested. The results showed that the overall porosity and permeability of the carbonate reservoir formation were low, and that there was a potential for water-blocking damage. There were micro-fractures with a width of 80–120 μm in the formation, which provided channels for drill-in fluid invasion. The average content of dolomite is 90.25%, and precipitation may occur under alkaline conditions. The polymeric drill-in fluid had good rheological and filtration properties, and the removal rate of the filter cake reached 78.1% in the chelating acid completion fluid without using gel breakers. In the permeability plugging test, the drill-in fluid formed a tight plugging zone on the surface of the ceramic disc with a pore size up to 120 μm, and mitigated the fluid loss. In core flow tests, the drill-in fluid also effectively plugged the formation core samples by forming a thin plugging layer, which could be removed by the chelating acid completion fluid, indicated by return permeability higher than 80%. The results indicated that the drill-in fluid could mitigate formation damage without the treatment of gel breakers, thus improving the operating efficiency and safety.

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Section: Resultsmentioning

confidence: 99%

Formation-Damage Mechanism and Gel-Breaker-Free Drill-In Fluid for Carbonate Reservoir

Fang

Zhao

Sun

et al. 2022

Gels

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Next Generation Ceramic Sand Screens as Open Hole Completion Solution in High Rate Erosive and Corrosive Well Environment at Dvalin HPHT Field, Offshore Norway

Ritschel

Storhaug

Dahle³

et al. 2020

SPE Asia Pacific Oil &Amp; Gas Conference and Exhibition

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The Dvalin gas field is located in the Norwegian sea on NCS and is operated by Wintershall DEA Norge. It is supported by two independent reservoir structures, Dvalin East and Dvalin West. The field was explored through wells 14S and 15S in 2010 and 2012, respectively. The field is characterized by dry gas, high CO2, high temperature (160 °C) and high pressure (SIWHP 620 bar). The targeted Garn sandstone has good reservoir quality, but with a high permeability contrast. The field development was sanctioned in 2016 and calls for a 4 well solution through a centrally located subsea template, producing gas back to the host platform Heidrun TLP 15 km away. Water depth at location is 380 m and targeted reservoirs are at 4140 m MSL (East) and 4240 m MSL (West). Production plateau rates are estimated to be approximately 106 MMscf/D (3 million std m3/d) per well where thin high-permeability zones within the Garn formation are expected to dominate the inflow. The lateral facies development is thought to be relatively homogenous throughout the field, thus S-shape wells falling off to vertical through the reservoir will ensure effective drainage. Sand failure is expected after short time of production and would increase the risk of erosion causing severe damage to well jewelry and production facilities. It has been decided to integrate sand screens as a means of downhole sand control as part of the primary lower completion design. The sand screens will offer sand control, erosion resistance, hot spotting resistance as well as robustness towards a full hole collapse during reservoir pressure depletion. As the subsea completions are carried out from a mobile drilling unit in harsh environments, protection of the sand control filter media during installation is of utmost importance. This paper will describe the selection process of sand control and qualification steps carried out to use ceramic screens as the stand-alone screen solution for successful deployment and integrity for the Dvalin field development

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Systematic Selection of Drill-In and Completion Fluids for Development of the Dvalin HT Gas Field - Part II: Successful Clean-Up Validates Experimental Qualification Approach

Czuprat¹,

Eriksen

Clinch

et al. 2021

Day 4 Thu, March 11, 2021

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Formation damage by the drill-in fluid has been identified as a major risk for the Dvalin HT gas field. To ensure the long-term stability and mobility of the mud even after an extended suspension time between drill-in and clean-up of the wells, a novel static aging test under downhole temperature and high pressure was conducted. Experiments have shown that the downhole stability is commonly underestimated when the surrounding pressure is lower than in the field. Thus, a high-pressure cylinder was used in vertical orientation in a heating oven with a pressure pump regulating the pressure up to 200 bar. The reservoir section was drilled with the optimized organo-clay-free oil-based drilling fluid (OCFOBDF) specified in the qualification phase. Tracers in the lower completion were used to identify clean-up from the upper high-permeability streak and the deeper (relatively lower) high-permeability streak. Due to extended wait on weather after drilling and completion of the first of the four wells, the lag time until clean-up was almost 11 weeks (74 days). It could be experimentally shown that the qualified OCFOBDF system weighted with micron sized barite remains mobile without phase separation even after static aging at 160 °C and 200 bar for the maximum estimated lag time between drilling and clean-up of 3 months. The absence of a gas cap in the set-up also better represents downhole conditions in the reservoir section and has shown that it improves the fluid´s stability. The clean-up of the well was successful with a maximum flowrate of 3.0 MM Sm3/d. Analysis of the tracers has proven that clean-up was successful for the entire reservoir section, including the deeper part. It could be concluded that in alignment with the lab tests that the mud fulfilled its requirement to be mobile even up to three months. Because of the superior properties, settling of solids (bridging and weighting material) could be avoided, resulting in no blockage of the (lower part of the) reservoir. The use HPHT aging has been the key to proving the long-term stability and mobility of the combined Drill-In and Completion Fluid. This technique falls outside of current API RP testing practices but is believed to be highly beneficial for qualification of fluids that will be left in the lower completion for long periods, especially in open hole completions under high temperature and pressure.

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Systematic Selection of Drill-In and Completion Fluids for Development of the Dvalin HT Gas Field

Cited by 7 publications

References 0 publications

Formation-Damage Mechanism and Gel-Breaker-Free Drill-In Fluid for Carbonate Reservoir

Formation-Damage Mechanism and Gel-Breaker-Free Drill-In Fluid for Carbonate Reservoir

Next Generation Ceramic Sand Screens as Open Hole Completion Solution in High Rate Erosive and Corrosive Well Environment at Dvalin HPHT Field, Offshore Norway

Systematic Selection of Drill-In and Completion Fluids for Development of the Dvalin HT Gas Field - Part II: Successful Clean-Up Validates Experimental Qualification Approach

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