AGR delivers Enhanced Oil Recovery study in Heglig field - AGR - Upstream Services, Training & Software
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AGR delivers Enhanced Oil Recovery study in Heglig field
Published 20.08.2015
AGR was assigned to provide technical recommendation for pilots, assess the economics, uncertainty and risk analysis of Heglig field to ensure the development of more efficient oil recovery techniques that would be technically, economically and environmentally more viable.

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AGR experts Gudmund Olsen, Engineering Manager in Oslo, and Rita-Michel Greiss, BD Manager for Reservoir Management in Aberdeen, discuss why multidiscipline interaction and local skills development were critical for analysing the performance of various scenarios for more advanced Chemical Enhanced Oil Recovery in Sudanese field also enabling future sustainability of the much-required Sudanese petroleum industry.


Following secession 2011, Sudan’s hydrocarbon production reduced from approximately 450,000 to 100,000 barrel-per-day (bpd), rendering the Sudanese production status from a substantial oil exporter to a nation just self-sufficient in petroleum.

In February 2012, as part of Norway’s commitment to the implementation of the Comprehensive Peace Agreement (2005) including support to developing the petroleum sector in Sudan, Norway and Sudan signed a Programme Agreement. In March of the same year, the Norwegian Ministry of Petroleum and Energy and Sudan’s Ministry of Petroleum signed an Institutional Cooperation Agreement. Within the Agreement, Heglig Field was selected as part of the Oil for Development (OfD) programme focussing on petroleum policy including legal and institutional framework, resource and HSE management.

The Enhanced Oil Recovery (EOR) Scope of the Programme was administrated by the Norwegian Petroleum Directorate (NPD) on behalf of OfD. International Petroleum Associates Norway (IPAN) were contracted to be technical advisors to OfD (NPD) whereby AGR were sub-contracted to perform the technical subsurface studies and conduct training of local authority employees.

Heglig oilfield, situated within NW-SE trending Muglad Basin (SW Sudan) is part of the Central African Rift System. Three phases of rifting have occurred between Cretaceous and Tertiary, resulting in deposition of at least 13 km of sediments in this basin. Commercial hydrocarbons are sourced from the Aradeiba Main, Bentiu 1, Bentiu 2 and Bentiu 3 wells. Heglig boasts much of Sudan's proven oil reserves, producing almost half the country’s 115,000 bpd output. Heglig oilfield was first developed in 1996 by Arakis Energy (now part of Talisman Energy) and is today operated by the Greater Nile Petroleum Operating Company, GNPOC, reportedly having had peak production in 2006. Heglig oilfield is connected to Khartoum and Port Sudan via the Greater Nile Oil Pipeline.
To improve Heglig oilfield production, OfD programme together with team representatives from the Sudan’s Ministry of Petroleum, GNPOC and AGR technical expertise, set about investigating best methodology for enhanced oil recovery. AGR was tasked with managing the team evaluating geological and reservoir simulation modeling scenarios. The study was conducted in two main phases with a third phase recommending future planning process.

Phase 1: Data gathering of all geological, production and well data to construct reservoir and economics database.

Phase 2: Reservoir characterisation and understanding was essential to production simulation modeling of various EOR feasibility scenarios. This proved to be a more in-depth process with review and re-evaluation and, where required, interpretation for geophysical picks, geology and petrophysical rock physics. Data posed some challenges, primarily because of poor seismic quality (low frequency content, 20-24Hz). The team’s attempt to use continuity failed to give enough detail to match the log facies, and seismic amplitudes proved overall inconclusive. This had some implications onto the geological uncertainty regarding facies distribution and continuity. However well log data aided well-to-well correlations rendering the choice of geological robust areas suitable for testing EOR pilots.

Reservoir simulation was performed using a history matched simulation model. The history match was robust and to a large degree independent of detailed facies architecture. This was mainly due to high net sand content. However, predicting future reservoir performance on a well-to-well basis proved to be more uncertain. More detailed modeling and reservoir characterisation was recommended for further optimisation of a pilot design.

Drilling and facilities capabilities of Heglig oilfield were critical to assess potential feasibility for EOR. Taking all the above into careful consideration, AGR worked closely with GNPOC to analyze the concept studies, seek out technical recommendation for pilots, assess the economics, uncertainty and risk analysis to ensure the development of more efficient oil recovery techniques that would be technically, economically and environmentally more viable.

Various scenarios of EOR strategies

Based on the outcome of the sector model screening, it was decided that the EOR actions to be incorporated in the full field model would be: Horizontal producers in Aradeiba F/Bentiu 1 and Polymer Injection in Aradeiba Main and Aradeiba F/Bentiu 1. 

Table 1 Overview and results from EOR measures applied to the field model of Heglig 

Combined case: Horizontal producers and Polymer injection.

Reference Case - pertained to full field model with existing drilling and production plans for oilfield without any EOR actions.

Horizontal Producer Wells

Horizontal Producer Wells – New infill wells within reservoirs (Aradeiba F/Bentiu 1) required specific length to obtain an adequate initial production (PI) and sufficient reservoir contact, the presence of underlying active aquifer preferred. Simulations including inflow control device (ICD) completion gave small increase to overall recovery. The risks pertaining to horizontal drilling was a combination of more directional well placement and associated expenses in comparison to vertical wells, requiring more thorough planning. 

Polymer Injection

This method is expected to enhance oil recovery by improving an unfavorable mobility ratio for water displacement. The EOR potential was dependent on the polymer viscosity. 12 cp based on lab data was considered a highly optimistic case, whilst 1cp was considered most realistic case due to polymer break down and degradation. Polymers were sensitive to high temperature and high salt concentration. Heglig reservoirs varied from 740– 900C, therefore it was thought not to be problematic for the most shallow reservoirs. Connate water proved to be fresh. It was observed premise for surfactant injection, high residual oil saturation in water swept zones. The aim of surfactants was to reduce the residual oil saturation in water swept zones. The residual oil saturation in the water swept zones of Heglig was unknown. Risks with chemical injection varied from back production in the aspects of facilities; water handling and polymer degradation during injection could decrease the desired viscosity.

A Combination of Producer Wells and Polymer Injection

All cases were constrained by a stepwise decline in total field liquid rate, starting at 220,000 bbl/day. The stepwise decline in liquid rate was based on liquid production in the Reference case. The plan for Heglig two new water injectors in Aradeiba Main were planned for pressure maintenance.

Figure 1: Simulation Results – EOR Potential and Production Curves

Cumulative produced oil 1.1 2014 was 154MMstbo.

As illustrated in Figure 1, applied EOR actions generated extra oil compared to the Reference case. Evidently horizontal wells saw increase of the cumulative production instantly after application, whilst the effect of the polymer injection was not seen until the recovered volumes.

Technical Conclusions

The assignments resulted in the recommendation to perform FEED studies on the selected Pilot(s) to support the FID for the pilot(s). Recommended work prior to the FID evolved in learning from Phase 2:

G & G
  • Re-process seismic to improve frequency content
  • Interpret shallow events to see if they can explain features in depth
  • Implement G&G and Petrophysical work in field static model for a detailed geological analysis of pilot area(s)
  • G&G input to history matching

Reservoir Engineering
  • Take fluid samples analysis for viscosity and asphaltene content
  • Analysis of final results from core experiments and update simulation model

Well planning. Multidisciplinary effort
  • Detailed geological evaluation of selected area
  • Well design & borehole stability study
  • Risk and contingency planning

Pilot design and detailed planning
  • Design pilot facilities (front-end engineering design)
  • Impact assessments: Production facilities & Environmental
  • Plan infrastructure and logistics 

Training for much required sustainability
The OfD project of Heglig oilfield EOR study was challenging on many levels due to restriction of available complete data and previous historical information. The multidiscipline interaction was critical to the overall study. Other challenging aspects were integration of knowledge and information and selecting activity actions: investigating the 3 main scenarios, from Reference case of no change to further infill horizontal wells to more advanced Chemical Enhanced Oil Recovery by utilisation of polymer injection to combining cases 2 and 3 to optimise EOR pilot.

The Heglig oilfield study also conveyed the importance of providing knowledge transfer in the form of training the Sudanese geoscientists and engineers to enable future sustainability of the much-required Sudanese petroleum industry.

For assistance in Reservoir and subsurface challenges, please contact our global Reservoir Management team.

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