The Yibal Khuff/Sudair reservoirs were discovered in 1977. The field contains both Non-Associated Gas in the Sudair & Lower Khuff reservoirs and Associated Gas with oil rims in the Upper Khuff reservoirs. The Upper and Lower Khuff hydrocarbons contain 2–3% H2S and 4–6% CO2, whereas the Sudair gas contain 1–1.5% CO2 and less than 50 ppm H2S. The Field Development Plan (FDP), a multibillion dollar sour development project, was completed in 2011 proposing a total of 47 wells, 34 dedicated horizontal/vertical wells for oil rim production and 13 commingled vertical/deviated gas wells, and the construction of new sour surface facilities with a gas production capacity of 6 MMm3/day.
FDP execution started in 2016 while the details of field start-up, scheduled a few years later, were still being planned. As part of this planning, it was noticed that a number of pre-drilled wells required perforation and clean-up before facility startup. Due to the time necessary to prepare all the pre-drilled wells, pre-production wellbore cross-flow was expected to occur in wells located in the West block of the field. A dedicated subsurface team was assigned in 2017 to evaluate and mitigate the potential risks associated with this expected cross-flow through the wellbore resulting from the pressure difference between the Lower Khuff and Upper Khuff layers.
This paper covers the integrated approach that the team followed to address the expected cross-flow issue, including: Basis for pre-production cross- flow The quantification of the cross-flow using analytical and numerical simulation methods The assessment of the impact of cross-flow on process safety and the environment (i.e. drilling risks with potential blow out of sour gas) and social responsibility (i.e. production capacity and ultimate recovery losses resulting in lower benefits to the community) The identification and assessment of solutions to stop/reduce the cross-flow The implementation of a robust and feasible mitigation plan
Basis for pre-production cross- flow
The quantification of the cross-flow using analytical and numerical simulation methods
The assessment of the impact of cross-flow on process safety and the environment (i.e. drilling risks with potential blow out of sour gas) and social responsibility (i.e. production capacity and ultimate recovery losses resulting in lower benefits to the community)
The identification and assessment of solutions to stop/reduce the cross-flow
The implementation of a robust and feasible mitigation plan
The conducted study demonstrated that the impact of cross-flow at well level would be severe. The cross-flow rate could reach up to 25-137 Km3/day/well, while the field level cross-flow rate could reach up to 400 Km3/day. The oil rate capacity reduction in the West Block wells could reach 20-30% at start-up, resulting in a total only 1% oil ultimate recovery loss at field level since the West block contribution is small to total production and West block wells are constrained. The study also showed that the casing design is adequate and drilling risks are manageable even in case of cross-flow. Out of several solutions identified to stop/reduce cross-flow, phasing perforation was considered the most robust and feasible option.
This paper presents the novel approach of a collaborative study that resulted in improved safety and reduced environmental risks and potential ultimate recovery losses. It also presents the methodologies used to allow the Assessment and Mitigation of Pre-Production Cross-flow and evaluation of the best option to mitigate the cross-flow in order to minimize the impact of cross-flow at minimum cost, well interventions and impact on well deliverable.
Mourad, Ahmed (RE: Petroleum Development Oman) | Awadhi, Mahmood (RE: Petroleum Development Oman) | Calvert, Stephen (PS: Petroleum Development Oman) | Djermouni, Karima (PG: Petroleum Development Oman) | Hattali, Ahmed (PP: Petroleum Development Oman) | Nabhani, Abdullah (PT: Petroleum Development Oman) | Noirot, Jean-Christophe (RE: Petroleum Development Oman)
The development of low porosity, low permeability carbonate oil reservoirs remains a challenge in the industry. Identifying a technically and economically viable development is further complicated when high pressures, high temperatures & high H2S concentrations are encountered at large depths. For such reservoirs, depletion developments are typically the only economically justifiable option but typically result in very low Hydrocarbon Recovery Factors. This paper presents a case study of a complex field located in the south of the Sultanate of Oman that includes a carbonate stringer reservoir encased in the Ara Salt. A viable Miscible Gas Injection (MGI) development scheme has been identified and turned into an economical option for this field.
The field X A3EC was discovered in 2011 within the Greater Birba area. Since it was put on production in 2013, the performance of this carbonate stringer has been relatively poor compared to other analogue fields. No feasible technical solution could be identified to develop the field beyond the very low estimated ultimate Recovery Factor (~6%) achievable under depletion. Alternative developments could not be sanctioned mainly because of poor economics resulting from limited expected incremental recovery. Moreover, the drillability of additional wells could not be confirmed following subsurface re-interpretation & dynamic history matching of the available pressure data.
In 2017 a study was carried out that incorporated newly collected pressure data, seismic and geological interpretations, as well as static & dynamic modeling. A new approach to history matching was also applied. This study turned further field development from technically unfeasible into an economically attractive & doable project. Moreover, new appraisal and well stimulation plans were identified to address the remaining field uncertainty on the in-place volume and well productivity. The proposed technical solution for further development of Field X A3EC involves a phased implementation of a MGI scheme which will increase the expected Recovery Factor in the target zone by more than 35 %. The drillability of the targeted field area was established by reducing the uncertainty on the reservoir pore pressure through extensive dynamic simulation work supported by newly collected long-term pressure build-up data. Field X A3EC development will feed into and benefit one of the largest projects in the Middle East - the Rabab Harweel Integrated Project (RHIP) that is currently under construction, further adding to the value of this large integrated facility.
This paper highlights the challenges faced whilst developing complex contaminated oil carbonate reservoirs and identifies technically feasible solutions for further development of such fields via an integrated approach.
Mourad, Ahmed (Petroleum Development Oman) | Calvert, Stephen (Petroleum Development Oman) | Djermouni, Karima (Petroleum Development Oman) | Hattali, Ahmed (Petroleum Development Oman) | Nabhani, Abdullah (Petroleum Development Oman) | Noirot, Jean-Christophe (Petroleum Development Oman) | Naamani, Ali (Petroleum Development Oman)
The development of high rich gas condensate carbonate reservoirs remains very challenging for the industry especially when the fluid is near critical conditions Ref (5). In some cases, the presence of high pressure, high H2S and CO2 in these reservoirs adds further to the complexity. In these circumstances, it is very important that detailed field development screening and planning are conducted to identify effective and cost competitive development solutions early in a fields life, preferably before starting commercial production.
A compositional simulation model of the richest gas condensate carbonate reservoir in the south of the Sultanate of Oman has been built to identify and select an optimum development scheme for the field. A representative fluid model based on Equation of State (EOS) is used for predicting the complex and dynamic phase behavior of the reservoir hydrocarbons. The performed simulations confirm that achieving maximum ultimate recovery for both gas and condensate is very challenging in this type of reservoir. The most effective recognized technique for maximizing the condensate recovery is gas recycling for pressure maintenance. A feasibility comparison was performed between no gas injection (depletion production), partial pressure maintenance (10 and 20 years of gas re-injection) and full pressure maintenance (long term gas re-injection). In addition, different sensitivities were considered to come up with an optimum development based on key economic indicators: Net Present Value (NPV); Value Investment Ratio (VIR) and Unit Technical Cost (UTC).
On the basis of the study results, it clearly appears that a gas recycling development is the best option to significantly increase condensate recovery (up to doubling it). However, economical evaluations show that a gas depletion development leads to higher NPV and VIR, mainly due to the early production of gas and the expected high surface facilities Capital Expenditure (CAPEX) associated with gas recycling in this type of high pressure, high souring, and very rich gas condensate carbonate reservoir.
This paper highlights and summarizes the challenges faced during the identification of a cost competitive development in high-pressure, highly sour, very rich gas condensate carbonate reservoirs.