Storage and Sequestration of CO 2 in the In Salah Gas Project

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1 Storage and Sequestration of CO 2 in the In Salah Gas Project Fred Riddiford Said Akretche, Abdelaziz Tourqui In Salah Gas Project, BP Exploration Ltd, London. Algerian Ministry of Mines and Energy, Algiers. In Salah Gas Project, Sonatrach, Hassi Messaoud. Introduction Throughout the 80 s and 90 s the importance of gas as an alternative clean replacement fuel for coal and oil, led BP and Sonatrach to form a Joint Venture partnership to explore the potential for economic development of a number of large gas fields located in the remote Central Sahara region of Southern Algeria. Gas from these fields would target the expanding southern European gas market, as the energy providers looked for cleaner fuels to meet the global targets for reducing emissions of Green House Gases. An extensive regional exploration and appraisal programme in this area led BP and Sonatrach to sanction the In Salah Gas (ISG) Project, in Feb 2000, with the development and production of the first gas fields planned for mid Total gas production from Algeria averages today around 50 billion cubic metres per year, with upwards of 90% exported to Central and Southern Europe, making it one of the main European gas suppliers. This volume is predicted to increase to over 85 billion cubic metres per year, as opportunities are taken to place additional volumes into the expanding European gas market. The In Salah Gas Project will contribute a large part to these expanding gas volumes by placing ~9 billion cubic metres per year into the Algerian gas supply chain, at Hassi R Mel. Gas production by the ISG Project is sourced from the deep Devonian and shallower Carboniferous reservoirs that lie within the Ahnet-Timimoun Basin in the Algerian Central Sahara (Figure 1). The northern most field being developed, the Krechba field, lies some 520 km south of the Hassi R Mel super-giant gas field, which provides the nearest infra-structure for gas export. Initial exploration activity commenced in the Ahnet- Timimoun Basin during the 1950 s and demonstrated its prospectivity with some 40 gas discoveries recorded from more than 60 exploration wells. However, the enormous production potential of the Hassi R Mel gas field was more than adequate to meet domestic supply and gas demand from Europe, which when combined with the remoteness of the In Salah region and its lack of infra-structure, have until now prevented any serious attempts to develop these discoveries. Development of the eight gas fields, which make up the In Salah Gas Project, are phased with the initial sales gas profile being met by production from the three most northerly fields of Krechba, Teguentour and Reg (Figure 1). These fields will be used to sustain the initial plateau production rate of 9 bcm/a, after which development of the southern fields will be used to maintain and extend the duration of the plateau. Figure 1. Map of In Salah Gas Project Area

2 Environmental Review Prior to project sanction, during the early development planning stage, ISG undertook to fully evaluate its emissions profile and put in place procedures, which would allow it to manage and reduce the environmental footprint of the project. The consequence of this early commitment to environmental management was seen in the assignment of the ISO accreditation pre-construction, this making ISG the first project of its type to achieve this recognition in the design stage. This commitment to understanding life of projects emissions also gave a clear insight into the opportunities that existed and the design and cost implications at a time when changes could be managed and implemented ahead of finalising the project scope. The full review of the emissions reduction portfolio (Figures 2a & 2b) showed on a like for like cost per tonne comparison the merits and materiality of the opportunities and clearly highlighted the significant saving associated with CO 2 re-injection, which offered the largest single reduction in emissions for the project at up to 1.3 million tonnes per year, giving a predicted total life of project sequestered volume in excess of 20 million tonnes. This represents ~60% of the potential emissions profile of the ISG Project and when implemented will be one of the largest sequestration and storage projects in the world FC7 FC14 17 $/Te CO 2 Exhaust Gas Removal $/Te 3 $/Te FC FC CO 2 Re-Injection Scheme VE $/Te 20.0 FC4 FC3FC13 FC1 FU2 VE3 GF2 FC5 0.0 FC6 FC2 FC12 0 2,000,000 4,000,000 6,000,000 8,000,000 10,000,000 12,000,000 14,000,000 16,000,000 18,000,000 20,000,000 Reduced GHG / CO2 Equivalent Emissions (Tonnes) FC5 2.0 Power Recovery Turbines 1.0 Optimised CO 2 Removal Scheme FC2 FC6 FC1 VE3 FC3 FC13 FU2 GF , , , ,000 1,000,000 1,200,000 1,400,000 Reduced GHG / CO2 Equivalent Emissions (Tonnes) Figure 2a. Emissions Reduction Portfolio Figure 2b. Facilities Emission Reductions Significant opportunities for reducing emissions were also identified through waste heat recovery and deferred export compression at the main Krechba facilities, which provided a further savings of close to 0.2 million tonnes per year in the early years of the project. When combined with low No x technology for turbines and gas engines and conversion of HP and LP process flare gas to CO 2 a total project emissions savings in excess of 1.5 million tonnes per year of equivalent global warming potential was achieved during the early years of the project. The predicted final emissions footprint for the project is shown in Figure 3 with the design savings implemented and the re-injection of produced CO 2 shown in yellow. CO2 Emissions by Source Tonnes 1,800,000 1,600,000 1,400,000 1,200,000 1,000, ,000 CO2(Injected) Flaring - Well Testing Flaring - Process Fugitives - Process Venting - Non CO2 Re-Injection Venting - Storage Tanks Combustion - Drilling Combustion - Emergency Power Combustion - Compression Combustion - Power Generation Combustion - Process Heat 600, , , Year Figure 3. Life of Project Emissions Footprint

3 The methodology developed to achieve the goal of minimising Green-House Gas (GHG) emissions was consistent with the risk based design philosophy of the development. This meant that the implementation of every conceivable option for reducing GHG emissions was not mandatory, since the judgement for inclusion required consideration of the cost, risk, maturity and suitability of the technologies for operation in the harsh desert environment of the Central Sahara. CO 2 Management To meet the export sales gas specification, the CO 2 concentration in the gas must be reduced to less than 0.3%, this significantly below the concentration present in the fields. It is therefore necessary to strip out the CO 2 component ahead of export, which gives rise to an associated production stream of high purity CO 2, which reaches a maximum of around 0.66 billion cubic metres per year, after a few years of production (Figure 4). Over time, this CO 2 production stream then drops, as the lower concentration southern fields are brought on production and the northern fields move into decline. The total volume of CO 2 handled in the production stream during the life of the project is predicted to be ~12 billion cubic metres. CO2 Production by Field Gas Production by Field CO2 (MMSCFD) Gross Gas (MMSCFD) Production Year GMD IS HMN GBF REG TEG (Dev) KB (Dev) KB (C10) Production Year Figure 4. In Salah Gas Production and CO 2 Injection Profiles. Options for sequestration of the CO 2 production stream centred on the identification of robust subsurface storage sites close to the planned In Salah gas process facilities. These sites required the reservoir cap seal integrity be demonstrated, that sufficient storage capacity be available to meet the predicted CO 2 volumes, that moderate to good reservoir properties be present and that the reservoir pressure be below 6000psi to negate the need to move into specialist compression equipment. Several opportunities for storage were evaluated during the design stage and ranged from distributed storage at each field location, to a single centralised facility and storage site. The high cost and increased system complexity associated with distributed storage, primarily around the need to employ multiple CO 2 stripping units, precluded this as an option. CO 2 removal at a centralised facility was therefore seen as the preferred option with the Krechba Field area viewed as the preferred location with the dried hydrocarbon and CO 2 gas streams from the Reg and Teguentour fields being fed up to the Krechba location, where a single treatment plant could be employed to remove the CO 2 to provide sales specification gas before export to Hassi R Mel via the 520 km ISG export pipeline. The need therefore was to identify sub-surface storage locations proximal to the Krechba Field area that could be used for the storage and sequestration of this CO 2 stream and which could provide for the volumes generated over the life of the project.

4 A number of options were considered in and around this area. These covered both deep and shallow Carboniferous and Devonian targets and structures both within the existing exploitation area, as well as opportunities outside this region. The results of this work culminated in the identification of a scheme, which would see CO 2 injection directly into the aquifer of the shallow Krechba Carboniferous reservoir, down-dip of the main hydrocarbon accumulation. To achieve a successful scheme, a number of peripheral injection wells would be required to access the sub-surface storage volumes and manage the placement of the injected CO 2 stream, such that the injected gas which is driven by buoyancy forces in the reservoir is retained within the aquifer zone as it migrates back towards the hydrocarbon trap, and does not enter the main field area until after it has been depleted and abandoned, this projected to be after 25 to 30 years of production. The Carboniferous reservoir at Krechba offered the benefit of good well coverage and associated log, core and test data, and importantly a high quality 3D seismic survey. These combined well and seismic datasets proved invaluable in assisting our understanding of the reservoir geology, while the seismic has more recently been successfully reworked and extended to the point where it is now possible to image the net reservoir section within the Carboniferous formation, so making simpler the task of modelling and understanding the range on injected CO 2 behaviour, over time. Krechba Field Geology The main gas bearing Carboniferous reservoir interval is prognosed from well and seismic data to comprise an incised valley feature deposit with the thickest and most extensive net reservoir development seen to lie along the axis of the valley(figure 5a). This section is the main gas bearing interval. Figure 5a. Net Pore Thickness C10 Reservoir Figure 5a. Coherency Displays C10 Reservoir Reservoir areas outside the gas-water contact to the south and east are predicted from analogues to contain less well developed net sandstones, which is confirmed by the seismic net thickness interpretation and the development of a seismic coherency dataset(figure 5b), which highlights

5 reservoir architecture and sand body geometries within the carboniferous reservoir section. This work, calibrated to the existing Krechba well stock, shows excellent agreement along the axis of the valley system where all of the 9 existing wells are located. The sharp contrast seen in the reservoir nonreservoir character of the seismic data was confirmed in 1998 by the drilling of the appraisal well Kb- 10, which lies outside the valley-fill to the west and confirmed the validity of the seismically derived attributes which were seen to be well calibrated in these areas. To the east there are no wells, so the seismic response in this area is less well constrained and therefore carried greater uncertainty and risk. This has now been addressed by the drilling of the first CO 2 injector Kb-501. The relationship between seismic amplitude and reservoir presence in Krechba was established shortly after acquisition of the 3D dataset in 1997/8. Amplitude maps and their interpretation, aided by seismic modelling, suggested that the reservoir was not continuous across the whole field. This interpretation was successfully tested by two appraisal wells drilled in More recently, seismic techniques based on attribute interpretation, coherence analysis, spectral decomposition and Q-filter techniques have increased our understanding of this reservoir and have allowed a quantitative description to be built of the net-pay. This heightened understanding of reservoir continuity, which clearly identifies a number of massive sinuous sand bodies within the axis of the system and a number of smaller feeder type features towards the edge of the valley-fill system has proved invaluable in the exercise of well targeting and the subsequent prediction of CO 2 migration and storage behaviour. Field CO 2 Sequestration Development Plan The development philosophy that is being employed for sequestration and storage of CO 2 in ISG is one of down dip aquifer storage. The CO 2 stream is to be injected into the aquifer zone in the main Krechba Carboniferous reservoir interval and will over time migrate back towards the main hydrocarbon accumulation and into the structural trap, which fulfils all the requirements and criteria identified for long-term injection and storage of CO 2 that have been outlined. Three injection well locations have been identified peripherally around the field to manage the placement of CO 2 with two located in the northern area within the main axis of the incised valley feature and one well located in the eastern area. It is predicted that during the early years of production and injection (up to 10 years) as the main gas accumulation is produced the injected CO 2 will be retained within the aquifer zone near to the injector locations(figure 6). However, over the longer term as volumes build in the reservoir the CO 2 will slowly migrate up-dip under buoyancy forces and the applied pressure field towards the structural crest of the main gas accumulation, moving into the main field area only after the field is depleted and abandoned. Sequestered CO 2 Volumes Sequestered CO 2 Volumes Sequestered CO 2 Volumes moving into the structural trap Aquifer Encroachment Aquifer Encroachment Aquifer Encroachment Sg diff years 15-5 Sg diff years Sg diff years Figure 6. Change in Gas Saturation(Sg) over time.

6 It is important that when employing such a scheme as has been outlined, that we fully understand the range in possible outcomes and have available contingency plans to manage the unexpected. Two sub-surface issues will control the success of this storage scheme, these principally associated with reservoir quality and connectivity. Reservoir quality is considered to be well constrained in the main field area as is connectivity, this evident from the seismic data which shows effectively continuous and connected reservoir with only minor faulting. The risk in this area is therefore seen in that the CO 2 might move more quickly than predicted under the effect of pressure and buoyancy forces. Sensitivities, run to explore the limiting cases in which the probability of such an outcome occurring were increased by eliminating any take-up of the CO 2 in the water, demonstrated that CO 2 leakage into the main field area had only a very low probability of occurring, this late in the fields production life and at very low rates 1-3 mmscf/d. Prediction of the injected CO 2 behaviour has been modelled both analytically as well as by numerical simulation. In the initial stages of project design analytical evaluation of seismically derived reservoir volumes for the key injection well locations was used to confirm CO 2 potential storage capacity and provide guidance on the likely breakthrough times at the producing well locations. The simple analytical models allowed the impact of uncertainty in sweep efficiency, CO 2 expansion factor and irreducible water saturation under CO 2 flood to be estimated. A more detailed evaluation of the impact of CO 2 injection on field production using simulation models, which captured the compositional effects of CO 2 in water and gas were used in the final design and placement of the injection wells. These models capture the full details of the reservoir variability seen in the seismic and well data and incorporated the compositional impact on relative permeability and CO 2 absorption. The simulation results confirmed the analytical prediction and robustness of this solution for storage and management of the produced gas CO 2 volumes, predicting that CO 2 breakthrough into the main field area would not occur until after field abandonment ie, 25+ years of production (Figure 6). Subsequent migration of the CO 2 into the structural trap at Krechba is predicted in the years after field abandonment, as fluids move within the system to re-establish equilibrium. First Injection Well Results The Krechba-501 well, located to the east of the main hydrocarbon bearing sands carried the greatest uncertainty of all the Krechba development wells, with no well control available in this part of the field area and un-calibrated seismic guiding the placement of the horizontal well section. To address these uncertainties a pilot hole was to be drilled ahead of committing to the horizontal section and would provide log, core and structural depth control, which would be critical to the optimal targeting of this well. The pilot-hole results confirmed key elements of the seismic interpretation in this area with 3 main reservoir intervals predicted, net pay estimated at ~0.8, interval average reservoir porosity at 13% and net pore thickness at ~2.2m, all of which were matched. The seismic was less accurate in its prediction of the gross reservoir interval, which was underpredicted by ~20% and represented an upside outcome for the well. The impact of this outcome was to put more storage volume in this part of the reservoir and provided greater assurance around this location for the storage and sequestration of CO 2. The pilot and horizontal sections are shown in Figure7, with the horizontal well bore targeting the high porosity channel sequences identified on the seismic and shown red in the X-section. Figure 7. Krechba-501. Pilot and Horizontal Well

7 Subsequent placement of the horizontal section proved to be very successful with the well contacting all the target sand intervals seen in the seismic and achieving a horizontal section in excess of 1250m for the injection of CO 2. Operational considerations meant that a full injectivity test was not completed on this well. However a short-term poor boy injectivity test has demonstrated the ability of the well to take in excess of 15 mmscf/d of CO 2, this in line with that predicted for this location. Forward Plan Two further injection wells will be drilled and surface facilities constructed during 2003/4 to complete the ISG storage and sequestration scheme. It is anticipated that this plant will be commissioned in 1Q2004 and is predicted that it will inject over 0.5 million tonnes of CO 2 by the end of 2004, with this increasing to in excess of 1.5 million tonnes by 2006/7. As the project moves into this operational stage it will be important that we have in place the processes and base line data for ensuring the safe and reliable storage of CO 2. Base line surveillance data will be acquired during 2003 to meet this need and will include: well integrity logging on all the production and injection wells, base line surveys to establish the natural surface seepage ahead of significant injection, integrate new well data into our understanding of the sub-surface for forward modelling. Additionally, work will be ongoing in the area of seismic fluid identification with significant benefits predicted for the project should it be possible to extend the analysis of the seismic data to discriminate fluid types in the reservoir. Conclusion The In Salah Gas Project when it is brought on production in 2004 will be one of the largest CO 2 sequestration and storage schemes in the world. This project implemented as a Joint Venture Programme between BP and Sonatrach has demonstrated: a clear and joint awareness and commitment to global environmental targets around emissions, that with Government, Shareholder and Project commitment major developments can achieve outstanding results and be recognised for their efforts in the field of environmental management, ie ISO 14001, and that complexity and project size are not blockers to achieving the extraordinary outcome, with large scale atmospheric disposal of CO 2 no longer seen as an acceptable option. The full evaluation of the project environmental footprint during the early design stage, allowed the project team to materialise significant emissions savings with a solution identified and now being implemented which will provide savings of ~1.5 million tonnes per year of equivalent greenhouse emissions, this in excess of 60% of total predicted project emissions. To the future, additional opportunities will exist as technology evolves for targeting utility emissions for power and compression and could provide further emissions savings for the project of up to 30%. ISG has defined the way forward for the future and outlined the processes that are necessary to manage the increasing needs and demands that are set on projects around environmental management. It defines what is possible in the future, with its impact and the lessons learnt predicted to guide our regulatory bodies and provide direction for operations into the future. Acknowledgements The In Salah Gas project team would like to thank the management of Sonatrach and BP for the opportunity to present this paper.