Oil production from the unconventional Vaca Muerta play is increasing as a result of a rigorous appraisal and exploitation strategy. Multiple wells have already demonstrated the potential of the Neuquén Basin, however optimization is still ongoing to determine the best practice for completing wells. A stand out difference of the Vaca Muerta play is its thickness (100 m to 450 m), as such a development strategy based solely on vertical wells is being considered in addition to the horizontal well strategy more commonly applied in other shale plays. The thickness of the Vaca Muerta formation creates new challenges and opportunities due to the stratigraphic variation in petrophysical and mechanical properties which can affect fracture effectiveness and well productivity. Completion design, geology and production performance need to be linked. Specifically, the geology of the Vaca Muerta formation, as is the case in most reservoirs, varies significantly more in the vertical direction in comparison to the horizontal direction. With optimum solutions not necessarily being intuitive, numerical simulation is critical as it enables a large number of variables to be analyzed and their individual impact understood and quantified. The objective of this paper is to present the four different approaches that have been used to build numerical models to represent the vertical wells in Vaca Muerta. These are: A single layer model with a planar fracture placed in a zone of improved permeability to represent the Stimulated Rock Volume (SRV) which is then surrounded by undisturbed matrix.A multilayer model with multiple planar fractures placed in an undisturbed matrix.A multilayer model with multiple planar fractures (one per stage), the SRV surrounding the fractures and the undisturbed matrix behind it.A multilayer model, where the SRV is modeled within a dual porosity model. This work shows how these models were constructed, the measurements that were honored and the estimation and justification of values assumed for unknown parameters. The impact of the different methodologies on the time taken and quality of the history match obtained and subsequent forecasts is also discussed. YPF has collected an extensive data set including PLTs, microseismic surveys, downhole pressure gauges, and pressure build ups, which has been used to constrain the numerical models. Building and history matching these models has been challenging but enables conclusions to be made about rock, fluid and completion interaction that cannot be obtained otherwise. The simpler models, have in some cases, enabled rapid estimates to be made for EUR which have subsequently been supported by the results from the more detailed modeling approaches.

The Vaca Muerta shale has been developed for oil and gas production since 2010 and to date nearly 500 wells have been drilled. The large amount of static and dynamic information from these wells has enabled fracture design and production strategy optimization. This paper details the methodology used to integrate all available data in 3D models, in order to understand the impact of rock properties in the production. The model was simulated using a commercial reservoir simulator, showing that hydraulic fractures are acting as a dual porosity system with a large conductivity (~10 D) connecting a low permeability matrix (~100 nD). We studied multiple wells in the history match (HM), using separator pressure and choke size as the control variables for the wells, and rates and pressures as comparison variables. A multi-segmented well approach was used to describe the pressure drop inside the well, and a vertical lift performance (VLP) table to describe the flow from the tubing all along to the separator including the wellhead choke. The static model included the seismic interpretation, stratigraphic framework, geomechanical and petrophysical characterization. Rock permeability, initial pore pressure and total fracture pore volume were calibrated with field measurements used as constraints in the HM process. Fracture conductivity degradation was introduced in the model to explain observed changes in the wells productivity. Laboratory tests are being designed to validate these hypotheses. We established early in the project that individual well HM were not unique. It was only through the HM of multiple wells that we were able to reduce the range of uncertainties affecting well performance (matrix permeability, initial water saturation and fracture height). This has given us a more reliable tool to obtain ultimate recovery estimation ranges. The described model showed a good prediction of a well with water lift problems, giving an accurate forecast for the incremental gas rate after a tubing diameter change. We concluded that the multi-segmented well model is a good representation of the water hold-up fraction behavior. This methodology enables us to integrate all the knowledge of the subsurface into a model that can be run in short simulation time (~30 minutes), allowing us to iterate quickly during the HM process. The model can be run for single wells or multiple wells and is flexible to adapt for new areas. We plan to use this methodology to design and monitor pilots in new blocks and to evaluate different development plans for existing projects.

In early 2007 the operator was looking at options to drill additional gas wells. A hydraulic workover unit (HWU) had been used to previously sidetrack a number of wells offshore Dubai and a decision was taken to investigate this option further. The goal was to drill the same well profile as a jack-up did on a previous campaign but at lower costs. The work scope for the HWU campaign would include the retrieval of the existing completion, setting a whipstock, milling through two casing strings, drilling 8–1/2" build-up section into the top of the reservoir, lining off with a 7" liner, horizontally drilling the reservoir section in 6–1/8" hole and finally completing with a 5–1/2" completion. Due to time constraints all planning including contracting was performed in a two months window prior spud. The operator selected three mother wells on a platform connected to the main field facilities, which included accommodation and logistical support. With the reservoir being at around 3,300 feet TVD, a total of 4,285 feet were drilled in the three sidetrack wells. A regional first achieved is the drilling of 1,500 ft of 8–1/2" and running of a 7" liner with a HWU. This paper will describe the planning, challenges, limitations, learnings from the campaign and the resulting innovations for future HWU projects, which includes the concept of 'using self-elevating-workover-platform' or 'lift boat' and purpose built, minimized footprint tank farms for standalone production platforms. Introduction The operator has previously used hydraulic workover units (HWU) on project campaign basis for well repairs, tubing change-outs and simple sidetracks. Until that time sidetracks drilled with HWU's were either 3–3/4" or 4–1/8" bit size with lateral lengths of around 2000 ft. Some of the HWU sidetracks had also used 2–7/8" off-bottom liners with swell packers. The intention from the subsurface team was to have a 6" minimum reservoir section of 1500 to 2000 ft horizontal lengths with a 4–1/2" open hole completion. With the given target, an in-zone sidetrack from a donor well was not possible and with a large pressure differential between the reservoir and upper formations the build-up section needed to be cased off. A further requirement was the necessity for a gas tight re-entry mechanism into the donor well, sealing off any potential leak paths into the annuli of the donor well. Conclusively, after a detailed engineering review of various options a 8–1/2" inch build section lined with a 7" liner tied back into the 9–5/8" donor casing was chosen. The reservoir was to be drilled in 6–1/8" open hole, which was identical to the well design from the previous Rheas well drilled using a jack-up rig. Drilling the 8–1/2" build section and running 7" liners with a hydraulic workover unit (HWU) was highlighted as a major challenge, but detailed technical reviews and 'drilling the well on paper' exercises, indicated the feasibility and the project sanction was awarded. Hydraulic Workover Unit (HWU) and Facilities A standard hydraulic workover unit (HWU) uses four hydraulic driven cylinders with one set of stationary and one set of traveling slips to push or pull tubulars. Depending on the design of the HWU the traveling distance or stroke varies between 9 to 12 feet only, which explains the slow tripping time of a HWU compared to a standard jack-up rig, which can generally handle triple stands and rack them in and out the derrick. If the HWU does not have the racking capability, due to platform load and/or space restrictions, then all tubulars have to be singled-in and out the work basket during each trip. During the Rheas campaign an average of 20 joints per hour while tripping were achieved, which meant that a trip typically took eight hours (excluding BHA handling) at a measured depth of 5000 feet. In regards to the pushing and pulling capabilities there are various designs and sizes available on the market; The Rheas project used a 340k HWU, which means this HWU was able to pull 340000 lbs and push 180000 lbs.

The Lajas formation in the Neuquén Basin, Argentina, has been identified as a key opportunity to supply the gas requirements of the Argentine economy. A number of fields are currently being developed in this formation with an ongoing exploration program likely to yield more discoveries. Maximizing the value of existing and new assets was the task at hand. To optimize the development, dynamic models were needed to produce forecasts for different development scenarios. One of the main issues to solve was how to represent in commercial dynamic software the hydraulic fractures and their interaction with a low permeability formation. The optimum approach to model induced fractures had to be identified. Additionally, flow tests of wells were infrequent and often gave contradictory results. Hence we explored a number of different options for controlling the history match and forecast such as controlling by gas rate, tubing head pressure and back pressure through the choke. We concluded that dual porosity modeling of the fractures offered an acceptable balance between computational overhead, absolute accuracy and flexibility. The main parameters adjusted to achieve the history match were the fractures half length, height, volume and conductivity/permeability that ruled the early behavior of the wells and the matrix permeability that conditioned their longer term productivity. Controlling the wells in the history match was found to be best achieved by control through the choke and line pressure. Tubing head pressure as well as gas and water simulated rates were cross checked against historical data. The vertical lift performance modeling of the wells was also found to be critical to achieve the history match. The pressure drop in the wells was modelled by lift curves from the well head to the first perforation and by segments from there onwards to understand their liquid loading. All this had to be taken into account due to the fact that wells were impacted by tubing, choke and line pressure changes through their production history. It was possible to optimize Lajas gas development by applying an integrated modelling methodology linking geology, reservoir and production engineering. The model helped justify new infill locations and estimate the difference in productivity between different Lajas geological sequences. The dynamic model results were compared with the outcome of other forecasting methods such as DCA Tipe Well, RTA and layercake dynamic models.