Mature fields

UAE Case Study Highlights Challenges of a Mature Gas-Condensate Field

Three onshore fields in the Emirate of Sharjah, United Arab Emirates, have more than 30 years of production history from more than 50 gas-condensate wells.


Three onshore fields in the Emirate of Sharjah, United Arab Emirates, have more than 30 years of production history from more than 50 gas-condensate wells. While existing resources could be recovered by drilling additional wells, the most economical solution would be to confirm that existing well stock has sufficient well integrity to allow the continued use of these wells safely.


The Sajaa asset consists of three retrograde condensate onshore fields. All wells are naturally flowing, with support from wellhead compression to reduce the effect of liquid loading on these mature gas producers. The reservoir was blown down to produce gas associated with rich condensate, water, and liquefied petroleum gas. With the reservoir’s long production history, its pressure has been greatly reduced.

Through use of a highly simplified upstream production technique, the wells continue to produce condensate-rich gas with the low-pressure regime. But, because of the reservoir-pressure decline, the production rate remains reduced. Therefore, surface gas compression is required to reduce backpressure and pump the gas to a nearby production facility for separation and, ultimately, custody transfer and sale.

Mature Well Status

The asset wells were completed with 5-in. tubing along with a nominal 7-, 9-, and 13-in. completion scheme. For ­production-optimization purposes, 10% of the wells produce directly up the production casing, while all the wells are completed packerless. The main purpose of the open annulus completion was to avoid the extensive problems and costs encountered previously with packer completions in the hostile environment and allow for chemical corrosion inhibition along the conduit of the A annulus (Fig. 1).

Fig. 1—Typical well construction in Sajaa fields and zones at risk.


The cement behind the casing is generally accepted as accomplishing vertical isolation, though not radial isolation, with the natural pore pressure being applied laterally through the cement as a worst case. Collapse is considered to be more critical as a parameter than burst during production, even more so in mature reservoirs with cemented barriers that support against burst conditions. Actual well-integrity failures in a well stock do not always imply a situation in which uncontrolled flow of fluids reaches the surface. Individual barrier failures in a specific well group depend on a variety of factors, such as geographical area, operator, drilling era, well type, and maintenance quality. Gas is expected to be the primary fluid lost when a multibarrier failure occurs.

he Sajaa asset features comprehensive active and passive barrier systems. Cemented-to-surface annuli and heavy-duty wellheads account for the passive barriers; continuous remote monitoring of the annuli and weekly visits to the well location are effective active barriers.

Well-Risk Ranking

Both carbon dioxide (4.5%) and hydrogen sulfide (0.2%) were identified in early wells. Subsequently, wells featured a packerless completion. The asset wells have relied on surface-based corrosion-management techniques, including continuous injection of corrosion inhibitor, which is pumped into a control line that subsequently injects the chemical between the casing string and the tubing, down the well, and into the producing fluid path. Additionally, corrosion-monitoring coupons are mounted downstream of the tree and have a documented record of regular retrieval, providing an overall corrosion rate for the wells. The corrosion-inhibitor injection rate was selected through a series of laboratory tests wherein the injection rates are optimized on the basis of corrosion-coupon results and monthly water samples throughout the well life cycle.

The coupon cannot reflect the corrosion rate effectively when the flow is either stratified or annular because the coupon will not be fully wetted. Because the asset’s gas production contains relatively small liquid volumes with high velocities from the wellhead compression systems, a turbulent effect of corrosive liquids would be expected to be reflected on the corrosion coupons. Corrosion of the wells was modeled according to corrosion-coupon data collected from April 1997 to September 2016. The results show the total radius loss of well tubulars averaged on an annual basis throughout the production life of the well. This method, although relatively inexpensive to test and allowing easy accumulation of additional data points, has the apparent limitation of wellbore conditions; the corrosion taking place in the tubulars downhole is at reservoir temperature and pressure with a steel grade that may not be the same as the coupons. With no direct corrosion measurements from the well, this method was considered to provide a representative assessment of what was occurring in the well, although the actual corrosion rates may not be linear throughout the completion.

The operator developed a comprehensive well-consequence-ranking tool featuring a set of parameters to assess the risk to the local environment and to the business unit. The parameters were ranked by importance and weighted on the basis of their contribution to the overall risk.

Fig. 2 shows the number of wells according to their risk-ranking percentage. Ten wells showed an elevated risk slope and, therefore, required immediate evaluation from the operator. The high-consequence wells received a de facto risk percentage of 40% and greater. The slope changes again for the tail end, with a consequence rating of 30% and less for 17 wells classified as low-consequence. The majority of wells lie in the middle region, with 26 wells having ratings between 30 and 40%. The rankings also can be connected to business needs. The table in Fig. 2 summarizes the revenue contribution from these wells, providing the operator a way to integrate the business and technical aspects of well-integrity management.

Fig. 2—Well-risk-ranking distribution and revenue contribution.


The aim of field logging in 2016 was to compare the risk-ranking criteria issued that year with field results and confirm that the criteria were rugged and appropriate for integrity assurance. Ten wells from the asset were selected for the campaign, of which five were classified as high-consequence, two as medium-consequence, and three as low-consequence. The objectives of this logging were combined with other field-development objectives, in which the integrity assurance of all wells in one field was essential to a potential injection project. Therefore, even though three of the four wells in the M field were low-consequence and one was medium-consequence, all were selected for logging. The remaining six wells were from the S field, which contributes the most to the production of the asset.

The operator implemented this technology on 20% of the well stock to obtain a fieldwide perspective of corrosion and metal loss. The activity was awarded to a contractor for logging and analysis. From 9 November 2016 to 9 January 2017, the contractor performed surveys on 10 different wells. To ensure health, safety, and environmental standards and minimize risk in rigless operations, wellsite activities were restricted to daylight times only. Therefore, the program for surveying three barriers of a well from surface to the total depth of 12,000 ft took approximately 3 days to complete. The survey was performed bottom-up after reaching the desired depth for analysis.

Results Analysis

Taking into account logging-tool speed, logging-history integrity, well geometry, and accuracy percentage, the operator and contractor used criteria provided in Fig. 6 of the complete paper to define the qualitative extent of corrosion for the analysis performed in all 10 wells. The criteria state that any corrosion percentage less than 10% is of minimal concern to well integrity, whereas corrosion rates greater than 25% require further analysis, with immediate investigation of cause and determination of a course of action to restore integrity assurance. The results from the corrosion-logging tool were interpreted with proprietary software. The pressure ratings for all tubulars logged were revised and downgraded per the corrosion percentages observed.

Final logging results were in the form of joint-by-joint analysis demonstrating the percentage of metal loss caused by corrosion across each of the three tubular barriers. The metal loss was compared with the grades for the casing to calculate the new remaining thickness and subsequently determine the casing burst and collapse ratings. The asset’s subsurface pore pressure was determined and was used to calculate the overburden pressure at different depths. These data were used to create snapshots of the 10 wells logged in 2016. These snapshots revealed the worst joints in the well. These data form the basis of the fieldwide revision of corrosion loss and the correlation of corrosion coupons with actual measured corrosion.

Corrosion logging using a magnetic imaging tool was performed in 10 wells to monitor corrosion status on the basis of well selection through the operator’s risk-ranking criteria. The corrosion-logging results were compared with corrosion-coupon readings from the 30 years of production.

Six wells in the S field were logged using the corrosion-thickness-monitoring tool. Corrosion levels averaged between 15 and 25% of thickness. The 9-in. casing showed the maximum corrosion levels compared with the 7- and 13-in. casings. The joint-by-joint metal-loss analysis was used to derive an average metal-loss profile for the primary flowing tubular and was compared with corrosion-coupon-predicted metal loss. Although, on an absolute basis, the metal loss observed by the downhole corrosion tools was higher than the corrosion-coupon prediction, the indication and trend of the risk ranking for the wells were in accordance with the observed corrosion percentage in the casings.

Four wells in the M field were logged using the corrosion-thickness-monitoring tool to confirm well integrity before they were subjected to high injection pressures. Two notable areas of fieldwide corrosion were observed in all wells: liner hangers and near-surface regions.

Liner Hanger. The 7-in. tieback was installed while drilling the well as part of the original completion strategy to provide support to the 9-in. casing against the overpressure shale seal. These wells were completed without the packer, so the fluid could travel up to the surface, causing corrosion to the A annulus and the tubing. The liner hanger showed maximum corrosion levels of up to 48%.

Near-Surface Corrosion. Corrosion of 20 to 25% was observed at the near-surface region of 2,000 ft in nearly all wells. The outermost casing showed the highest corrosion levels, which reduced progressively in the inner casings. This confirms a case of external corrosion in the wells.

Throughout the Middle East, a shallow aquifer is suspected to be present at this depth, which might be the cause of this external corrosion. Future well planning should consider this scenario and should have a relevant grade of casing installed to suppress the corrosion caused by the aquifer.

The Way Forward: Integrity Assurance

  • Each well will undergo further analysis on the basis of corrosion-logging results. Suitable workovers will be planned that will address all concerns of the damaged areas. The workovers will take into account the future application of the well (i.e., the field-development strategy).
  • Risk-ranking criteria are validated for existing factors, although more factors that can affect corrosion levels will be identified and introduced to the risk ranking to ensure a blanket corrosion-monitoring approach.
  • Lessons learned from existing corrosion levels of the wells will be applied to future well designs and completions. For example, liner-hanger location is a common point for corrosion. Therefore, liners will be avoided if possible or packers will be installed, isolating the hangers.
  • A bottomhole camera might be an efficient solution to determine if corrosion actually exists in the liner hanger region or if the gap between the liner and the tie-back, which is measured as metal loss, is caused by completion mechanisms.
  • More wells susceptible to collapse will be identified after updating the risk-ranking criteria with 2016–2017 observations.
  • No mechanical obstructions were identified in the 10 wells logged in this campaign. All wells are near‑vertical producers, with four wells to be converted to injectors on the basis of the pressure envelope defined by corrosion logging.
  • The corrosion surveys completed in the 10 wells provide a baseline of the logged well-corrosion status. Annual determination of the rate of corrosion is recommended.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188422, “Well-Integrity Management: Challenges in Extending Life of a Mature Gas-Condensate Field—A Case Study,” by S. Jain, M.A. Al Hamadi, H. Saradva, SPE, and J. Asarpota, Sharjah National Oil Company, and S.J. Sparke, SPE, M. Volkov, and H. Abu Rahmoun, TGT Oilfield Services, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.