The Australia Pacific LNG Project is scheduled to come online in 2015 and consists of the extensive development of substantial coal seam gas resources across the Surat Basin. A variety of unique and complex challenges are presented when undertaking the geological and dynamic modelling and performance prediction of the laterally discontinuous and thin coal seams within the Walloons package. These challenges require a targeted approach and evolving solutions. Specific challenges that have been assessed and addressed in the characterisation and modelling workflow of the complex Walloons coal seams include: – Complex coal packages exhibiting thin coal seams with high degrees of lateral and vertical heterogeneity – Appropriate prediction of uncertainty – Coal body distribution and connectivity – Application of learning from fine scale sector modelling to larger regional coarse scale models – Significant reservoir dynamics across large distances within Surat acreage – Production performance variation over time resulting from stress impacting the matrix – Vast scale of the Surat Walloons development combined with fast-cycle decision making – Adopting appropriate and unique workflows for regions of different production maturity The developed workflow addresses coal seam gas modelling challenges both within the history matching phase and in the subsequent probabilistic forecasting. The workflow identifies uncertain reservoir properties and their expected maximum ranges based on available data and previous studies. An uncertainty analysis is conducted with statistical approaches including Tornado Chart and Latin Hypercube (LHC) to identify the most influential reservoir parameters and fine-tune their ranges in order to optimize the probabilistic history matching process. Subsequently, assisted history matching and optimisation techniques follow a stochastic algorithm of experiments to reduce the mismatch and create convergence with the production history. A number of representative, non-unique history matched models are identified which satisfy matching criteria and capture the uncertainty of the subsurface. The selected acceptable history matched models, together with forecasting parameters and their ranges, including operational variables, are used in forecasting. Random sampling of uncertainties by LHC is used with assisted history matched cases resulting in thousands of forecasts based on which P10-P50-P90 probabilistic forecasts are selected. This paper presents solutions to address uncertainty, assisted history matching and performance prediction of the Walloons coal measures for rigorous forecasting, and incorporation of learnings from localized fine scale models into larger coarse scale modelling for time efficient, regional performance prediction.

Mitigating production decline is a challenging task that every oil company will be faced with at some point over the life of an oil reservoir. However, depending on the existing reservoir fluid and rock characteristics, saturation distribution, and the level of heterogeneity of the reservoir rock, Enhanced Oil Recovery (EOR) programs can be implemented to alleviate the decline in oil rate and improve overall recovery. This paper presents an example of a how a mature waterflooded field in southwestern Saskatchewan, Canada could be revitalized using Alkaline-Surfactant-Polymer (ASP) flooding. In this study, laboratory tests were undertaken to select effective chemicals and optimize concentrations that would yield the highest potential oil recovery. Subsequent radial coreflood experiments demonstrated a wide range of potential recovery that depended on slug size and chemical concentration. A detailed numerical simulation of the optimum core displacement was performed in order to calibrate the interaction of the EOR agent with the reservoir rock and fluids, and ultimately upscaled to the full field numerical model Reservoir simulation sensitivity runs were conducted in order to identify an optimum field development strategy using the selected ASP fluid. The results from this optimized development strategy were compared to the waterflood base case to demonstrate the potential upside of the chemical flood. This paper also presents a holistic roadmap for developing EOR projects from initial concept to field implementation and beyond.

The Spring Gully coal seam gas field of the Bowen Basin in Queensland, Australia has historically been developed using vertical wells that have been stimulated by either cavitation or hydraulic fracturing of the Bandanna coal measures. However, as the field development expands into lower reservoir quality in the fringe area of the field, there has been a shift to applying horizontal well designs with the objective of increasing economic return and minimizing environmental footprint.Surface to inseam (SIS pairs) have been successfully implemented in Queensland low permeability Permian coal seam gas fields. Four Surface-to-Inseam (SIS) well pairs (horizontal wells intercepting vertical producers) were drilled in Spring Gully in 2012 and 2013. Production performances of these pilot horizontal wells show improvement when compared to offset vertical wells. In order to understand the more complex fluid flow mechanism a detailed multi-segment horizontal well (MSW) fine scale simulation model was built to calibrate rate and pressure performance. Following the pilot well performance study, a large scale development optimisation exercise including spacing, pattern, orientation and well design was carried out on all future development regions. This work when coupled with a risk quantification exercise has provided an informed view on the cost benefit of applying this optimised horizontal well development in Spring Gully.One of the unique challenges in implementing optimised SIS horizontal wells in the Spring Gully field is the undulating topography with very steep, narrow ridgelines that are bounded by cliffs and very deep and generally inaccessible valleys. Therefore during early planning phase, the operator, Origin on behalf of Australia Pacific LNG applied practical compromise between subsurface and surface objectives in order to achieve the greatest overall value

The Spring Gully coal seam gas (CSG) field, operated by Origin Energy on behalf of Australia Pacific LNG, is located in the southern region of the Bowen Basin. Commercial production commenced in 2005 from the Late Permian Bandana coal seams. This paper describes the reservoir characterisation methodology employed to history match geologically unique regions of the Spring Gully field and to understand production mechanisms across the field. In addition, the paper presents a detailed discussion on how learnings from the developed region of the field has been applied to characterise the future development regions of the field for forecasting.The Spring Gully CSG field exhibits a large degree of localized heterogeneity and extensive regional geological variability. Strong gas productivity and rapid water gas ratio decline have been observed in the north-eastern region of the field. While in the western portion of the field there exists moderate gas productivity and minimal water decline. A comprehensive, multi-disciplinary evaluation of the Spring Gully CSG field reservoir and production characteristics was performed in 2014. A reservoir simulation model has been constructed based on a number of geological and reservoir characterisation studies, combined with reservoir inputs and production analysis. The integrated subsurface model forms the basis to understand Spring Gully CSG field production mechanisms and ultimately to perform production forecasts for reserve and resource estimates, for ongoing reservoir management needs and appropriately size gas and water treatment facilities.A novel approach of constructing the permeability and porosity distribution in the reservoir model was implemented. Historical well peak water and gas rate, rig testing water rate and welltest-derived permeability were used to construct the permeability distribution in the model. The permeability distribution was transformed to porosity distribution. The faulting and compartmentalisation were introduced in the north-eastern region of Spring Gully reservoir model during the history match stage to match the rapid decline of reservoir pressure. The learnings obtained from studying well production mechanisms and model history matching were subsequently applied to the undeveloped regions of the field. Extensive validation and quality control of forecast methodology, forecast parameters assumptions and life-of-field production forecasting were performed.

The Hannay field is located in Block 20/5c of the North Sea, approximately 150 km Northeast of Aberdeen. The development consists of two subsea producers tied back to Buchan via a 13.5 km pipeline. The production mechanism at Hannay is depletion with significant aquifer pressure support. The Hannay Field commenced production from a horizontal subsea well (Hannay 1) at an initial rate of 18,000 stb/day. However, the initial months saw approximately 9 tonnes of sand production transported into the production separators. In an attempt to mitigate sand production, the well was flowed below 10,000 BFPD.Reduced flow rates from the Hannay 1 well provided economic justification for a second producer.Hannay 2 was drilled approximately 1 year after field start-up.Due to sand production from the Hannay 1 well and sensitivity to water-based gravel pack fluid, it was necessary to complete the well with a cased-hole gravel pack.The installation of the gravel pack resulted in a large skin of 100. Acid was used to reduce this skin to approximately 50; however, the Hannay 2 productivity still remained significantly impaired. This paper presents the engineering studies conducted to evaluate and justify the perforation of the gravel pack in the Hannay 2 well to reduce well damage. These include rock mechanics, sand prediction analyses, and reservoir simulation work to evaluate the potential benefit and optimum interval to perforate to maximise oil recovery. Detailed well intervention planning was undertaken and successful operations conducted to increase oil production from the well by 3,000 BOPD.Incremental reserves of 1.0 mmstb will be realised for a cost of under £2 million. This shows the importance of a long clean-up period for wells that initially produce sand before adopting a conservative sand control strategy. Introduction The Hannay oil field is located 13.5 kms Northwest of the Talisman operated Buchan field. The discovery well 20/5c-6, drilled in June 1996 by Amerada Hess, encountered an oil bearing Lower Cretaceous Britannia Sandstone Member. Two drill stem tests were then carried out, producing 3,700 - 8,000 bopd. The first development well, 20/5c-8y (Hannay 1) was completed over the A and Massive sands with 5 ½" tubing.The total perforated interval was 755ft over a horizontal section of 1,235ft, with a cemented 7" liner. The well tested at a peak of 21,900 bopd.The 20/5c-8x sidetrack was required to be plugged back following severe operational problems when running the 4–1/2 inch liner. The Hannay Field came on-line on 21stMarch 2002, producing through an 8-inch pipeline to the Buchan Alpha platform.From Buchan oil is exported through a 12-inch pipeline to the BP operated Forties field and onwards via the 36 inch Forties Pipeline System to Cruden Bay. The initial months of production from Hannay 1 saw rapid water cut development accompanied by approximately 9 tonnes of sand production.Due to sanding, production from Hannay 1 was restricted and a second development well, Hannay 2, was planned to recover the reserves not recovered by Hannay 1 when the 8x-sidetrack was abandoned. The Hannay 2 development well (Hannay 20/5c - 9) was spud on 20th March 2003.The low angle well was located to target the local high to the east of the Hannay 1 sidetrack (20/5c-8x).This well location recognised the potential upside of the central high and was selected based on maximum forecast incremental reserves from simulation work in addition to reasonable proximity to the existing Hannay well to minimise geological risk. Although it was originally intended to complete the well with an open- hole gravel pack (OHGP), based on the initial sand production seen in Hannay 1, core testing identified that the Barrier Shale was highly sensitive to water-based gravel pack fluid.It was subsequently decided to complete the well with a cased-hole gravel pack (CHGP). Prior to installing the CHGP the casing was perforated at intervals in the A sands, and the massive sands to within 20 ft above the OWC.