Flow Impairment by Deposited Sulfur - A Review of 50 Years of Research Bruce E. Roberts Rock Isle Consulting Services Ltd., Calgary, Alberta, Canada Received March 30, 2017; Accepted May 11, 2017 Abstract: Sulfur deposition in the reservoir formation and its impact on well productivity and ultimate recovery has been investigated for close to 50 years. Experimental measurements and numerical modeling studies have focused on the phase behavior of the sulfur-sour gas mixture system and the flow of sulfur and natural gas through the formation. The key results from these investigations are reviewed in this paper. The implementation of the insights gained over these 50 years of research into the field development planning and operation of sour gas fields is described. Keywords: Sulfur deposition, sour gas, hydrogen sulfide, formation damage 1 Introduction Elemental sulfur is often present in significant quantities in sour gas at reser- voir pressure and temperature conditions. The equilibrium sulfur content of reservoir fluids decreases with pressure and temperature. Deposition of sulfur will occur in the reservoir, well tubulars, or surface equipment when the equili- brium solubility of sulfur becomes less than the sulfur content of the fluid. Although sulfur deposition in the well and surface equipment is a signifi- cant operational problem, it is deposition in the formation that most signifi- cantly impacts well productivity and ultimate recovery. Estimation of the performance of wells producing reservoir fluid containing elemental sulfur requires an understanding of the phase behavior of sulfur in sour gas mixtures coupled with aspects of the flow of sulfur and gas through the formation. In this review, the development of our current understanding of the deposition Corresponding author(s): [email protected] DOI: 10.7569/JNGE.2017.692504 J. Natural Gas Eng., Vol. 2, No. 1, June 2017 84 Bruce E. Roberts: Flow Impairment by Deposited Sulfur - A Review of 50 Years of Research process within the formation and its impact on gas well productivity over the last 50 years of study is outlined. An objective of this review is to demonstrate Flow Impairment by Deposited how advances in this understanding may be implemented into the field devel- Sulfur - A Review of 50 Years of Research opment planning and subsequent management of sour gas containing elemen- tal sulfur. Bruce E. Roberts 2 Field Experience Rock Isle Consulting Services Ltd., Calgary, Alberta, Canada The early insights into the nature of sulfur deposition and the resulting opera- tional issues may be attributed to the studies by J.B. Hyne and co-workers at Received March 30, 2017; Accepted May 11, 2017 Alberta Sulfur Research Ltd. Hyne [1] surveyed more than 100 sour gas wells world-wide and determined that a combination of high bottomhole pressure and well temperature with low wellhead pressure provided a favorable set of Abstract: Sulfur deposition in the reservoir formation and its impact on well conditions for deposition in the well. However, the study focused on deposi- productivity and ultimate recovery has been investigated for close to 50 tion in the well and surface equipment, with relatively little attention given to years. Experimental measurements and numerical modeling studies have the deposition within the formation. focused on the phase behavior of the sulfur-sour gas mixture system and the flow of sulfur and natural gas through the formation. The key results Deposition of solid sulfur in the formation has significantly impacted well from these investigations are reviewed in this paper. The implementation performance during production of Shell Canada’s dry, sour gas from deep, of the insights gained over these 50 years of research into the field fractured, carbonate reservoirs located in southwest Alberta, Canada. The H2S development planning and operation of sour gas fields is described. concentration of the reservoir fluid ranges from 15 to 30%, with initial pressure from 30 to 40 MPa, and temperature from 80 to 100 ˚C. In a case described by Keywords: Sulfur deposition, sour gas, hydrogen sulfide, formation damage Roberts [2], well production dropped rapidly from an initial rate of 320 103 3 3  to 100 10 m /d in 42 days. The well skin, as determined by a pressure  buildup test, increased from slightly negative before production to about +17 following this flow period. Hands et al. [3] noted that well life of the order of 1 Introduction only 2–3 years has been experienced for these gas pools. In a specific case, a horizontal well had become quickly plugged with sulfur and required side- Elemental sulfur is often present in significant quantities in sour gas at reser- tracking just beyond 50 m from the original well. Field experience also showed voir pressure and temperature conditions. The equilibrium sulfur content of that solvent treatments can remove deposition within natural fractures, but reservoir fluids decreases with pressure and temperature. Deposition of sulfur once the fracture has been allowed to bridge with sulfur, solvent treatments will occur in the reservoir, well tubulars, or surface equipment when the equili- become ineffective. brium solubility of sulfur becomes less than the sulfur content of the fluid. Deposition of sulfur is generally absent when the composition of the reser- Although sulfur deposition in the well and surface equipment is a signifi- voir fluid is high in heavier hydrocarbons (Hyne [1]). Sulfur which precipitates cant operational problem, it is deposition in the formation that most signifi- from the gas phase will dissolve into any hydrocarbon liquids which have cantly impacts well productivity and ultimate recovery. Estimation of the dropped out due to retrograde condensation. performance of wells producing reservoir fluid containing elemental sulfur The most detailed account of sulfur deposition within the formation is pro- requires an understanding of the phase behavior of sulfur in sour gas mixtures vided by Chernik and Williams [4] and Williams and Milligan [5] in their coupled with aspects of the flow of sulfur and gas through the formation. In description of production testing of Shell Canada’s ultra-sour (90% H2S) Bear- this review, the development of our current understanding of the deposition berry gas reservoir. The reservoir fluid was determined to contain approxi- mately 65 g/m3 (standard conditions) at a reservoir pressure of 37 MPa and 118 ˚C. At these conditions, sulfur would deposit in the formation as a liquid Corresponding author(s): [email protected] phase. The project consisted of production from two wells. Production through one well was via a large (88 m) perforated interval and was used to obtain DOI: 10.7569/JNGE.2017.692504 DOI:10.7569/JNGE.2017.692504 J. Natural Gas Eng., Vol. 2, No. 1, June 2017 © 2017 Scrivener Publishing LLC 84 J. Natural Gas Eng., Vol. 2, No. 1, June 2017 85 Bruce E. Roberts: Flow Impairment by Deposited Sulfur - A Review of 50 Years of Research Bruce E. Roberts: Flow Impairment by Deposited Sulfur - A Review of 50 Years of Research data on the productivity of a commercial Bearberry well. For the second well, Table 1 Experimental studies on the solubility of sulfur in fluid systems. only one meter of pay was perforated to generate a large pressure differential at the well to accelerate sulfur deposition. However, impairment of gas flow by Authors Fluid system H2S concentra- Pressure Temperature the near-well bore accumulation of liquid elemental sulfur was not observed. It tion (mol% ) (MPa) (K) should be noted that the Bearberry formation is highly permeable – the draw- Roof [7] H2S 100 to 30 316–383 down at the large perforated interval well was less than 1 MPa at 180 x 103 Swift [8] H S 100 35 - 140 394–450 m3/d. The results for Bearberry may not be completely applicable to much 2 tighter formations. Brunner and H2S and 1–20 10–60 373–433 Woll [9] 4 sour gas mixtures 3 Phase Behavior of Sulfur/Sour-Gas Systems Brunner et al. 7 sour gas 9–84 7–155 398–485 The following describe the main aspects of the phase behavior of sulfur-sour [12] mixtures gas mixtures that govern the sulfur deposition process within the reservoir. Gu et al. [10] H2S, 44–95 12–50 363–383 CO2, 3.1 Sulfur Solubility in H2S and Sour Gas - Experimental Data CH4 and 2 sour gas mixtures Kennedy and Wieland [6] provided the first data set on the solubility of sulfur in sour gas mixtures at pressures to 40 MPa and temperatures to 394 K. How- Migdisov H2S 100 0.5–20 323–563 ever, their results have been found not to be consistent with studies that fol- et al. [11] lowed. Solubility measurements in pure H2S have been reported by Roof [7], Sun and 7 sour gas 5–27 20–45 303–363 Swift [8], Brunner and Woll [9], Gu et al. [10] and Migdisov et al. [11]. Brunner Chen [13] mixtures and Woll [9] also measured sulfur solubility in four gas mixtures, with H2S concentrations ranging from 1 to 20%. Brunner et al. [12] followed up this study with additional measurements in seven gas mixtures that included a spe- 2. At a constant pressure, sulfur solubility in sour gas mixtures decreases cific examination of the impact of ethane and butane components on sulfur sol- with a decrease in temperature. However, the effect of temperature on ubility. Gu et al. [10] measured the solubility of two sour gas mixtures of high the solubility of sulfur in pure H2S is more complicated. At pressures less than approximately 20 MPa, solubility increases with decreasing H2S concentration (44 and 95%). To facilitate the evaluation of equation of state binary interaction parameters, Gu et al. [10] also determined the solubility of temperatures. At higher pressures, the trend is reversed.