Recently two multilateral horizontal wells have been completed offshore using dedicated multistage hydraulic fracturing completions. The first well, located in the Central North Sea (referred to as ML-CNS), was stimulated using acid fracturing; while the second well, located in the Black Sea (referred to as ML-BKS), was stimulated using proppant fracturing. This paper presents the different drivers, challenges and lessons learned for each well while emphasizing the well construction and stimulation methodologies developed for the different reservoirs and field characteristics.
The field development drivers for drilling and completing these offshore hydraulic fractured multilateral wells, a first of their kind globally, was different for each case. The objective of the first project, initially considered uneconomic, was to engineer a technical solution for completion and production of two separate reservoirs with only one subsea well. The second project was seeking to optimize infill drilling from the last available slot on the offshore platform to maximize reservoir contact and production in the same reservoir. ML-CNS was a TAML Level 2 completion with a 14-stage, 5 ½" multistage completion run in each lateral and set-up for sequential acid fracturing. Operationally, the first lateral was drilled and stimulated, followed by the drilling and stimulation of the second lateral, using the drilling whipstock to navigate through the multilateral junction. ML-BKS was a TAML Level 3 completion that had a 6-stage, 4 ½" multistage completion installed in each lateral, which were proppant fractured following a sequence designed to minimize the jack-up rig time required. Both legs were drilled and completed prior to starting the stimulation, access to either lateral was achieved with the existing workover unit on the platform by manipulating a custom designed BHA.
The lessons learned from the first project executed in the North Sea were able to be transferred and applied to the second project in the Black Sea to allow for a more efficient and confident completion solution. Led by varying economical and regional constraints, the key factor for both wells centered on delivering operationally simple and reliable multilateral completion designs to economically meet the field development strategy in place.
To the knowledge of the authors and following subsequent literature research, both wells are a worldwide first for an offshore multilateral well completed with multistage acid fracturing and multistage proppant fracturing, and together they represent a new trend in cost-effective offshore field development through well stimulation. The successful case studies for both wells with the combined analysis of the benefits, challenges, and lessons learned will provide a guide and instill confidence with operators who find this approach beneficial with a view to applying it in other assets.
Following the significant reservoir depletion on Elgin / Franklin fields since 2007, drilling infill wells was considered to not only be high cost but also carry a high probability of failure to reach the well objective. The recent campaign on the Elgin field, one of the most heavily depleted reservoirs worldwide, demonstrated that infill drilling can be achieved safely while improving performance.
Drilling of HPHT infill wells on the Elgin field faced increasing challenges arising from the reduction of reservoir pressure that changed the stresses in the formations above and influenced the overall pressure regime. This stress reorganization in the overburden has affected the fracture network in these formations resulting in reduction in Fracture Initiation Pressure (FIP) and increase of gas levels.
Challenges were faced during the drilling of three wells in the 2015-2017 campaign. Loss events in Chalk formations in the intermediate sections significantly decreased the already Narrow Mud Weight Window (NMWW). A strategy to define and validate the minimum required MWW in 12-1/2" and 8-1/2" sections was developed following a complex subsurface well control event. Managed Pressure Drilling (MPD) technique was extensively used to safely manage gas levels and assess pore pressure.
Reservoir entry with more than 850 bar of overbalance remains the main challenge in infill drilling. A total loss event during first reservoir entry in the latest campaign confirmed the limitations of wellbore strengthening mud and stress caging materials available today.
Lessons learned from each well in this campaign were implemented to address these challenges and improve performance. This paper describes the Elgin HP/HT infill drilling experience and the specific techniques and practices that were developed to address these challenges and improve performance. The importance of Equivalent Circulating Density (ECD) management with very narrow MWW, successful high gas level management with MPD and depleted reservoir entry, shows that even in a highly complex environment, drilling performance can be improved allowing for further economical development drilling. The successful and safe delivery of the Elgin 2015-2017 infill drilling campaign demonstrates this at a time the industry moves toward unlocking the reserves of more challenging HPHT fields.
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
At the present time, more than 9,000 offshore platforms are in service worldwide, operating in water depths ranging from 10 ft to greater than 5,000 ft. Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Figure 1). The concepts range from fixed platforms to subsea compliant and floating systems. In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A.
Subsea processing using subsea separation and pumping technologies has the potential to revolutionize offshore oil and gas production. Between 1970 and 2000, millions of dollars were spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry did not rush to deploy the technology on a commercial basis. However, as the industry has moved into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, making small fields economically viable and large fields even more profitable.
Any reservoir simulator consists of n m equations for each of N active gridblocks comprising the reservoir. These equations represent conservation of mass of each of n components in each gridblock over a timestep Δt from tn to tn 1. The first n (primary) equations simply express conservation of mass for each of n components such as oil, gas, methane, CO2, and water, denoted by subscript I 1,2,…, n. In the thermal case, one of the "components" is energy and its equation expresses conservation of energy. An additional m (secondary or constraint) equations express constraints such as equal fugacities of each component in all phases where it is present, and the volume balance Sw So Sg Ssolid 1.0, where S solid represents any immobile phase such as precipitated solid salt or coke. There must be n m variables (unknowns) corresponding to these n m equations. There are m 2n 1 constraint equations consisting of the volume balance and the 2n equations expressing equal fugacities of each ...
Little is known about the nature and origin of microcrystalline quartz in sandstone reservoirs or mudstone reservoirs. We have utilized advanced analytical capabilities to improve our understanding of controls on microcrystalline quartz development in several examples where porosity is preserved in deeply buried sandstone reservoirs to understand the development in siliceous mudstones.
In this study, several advanced analytical techniques were used to evaluate the crystallographic and compositional controls on the formation of microcrystalline quartz. SEM/Cathodoluminescence (CL) imaging confirms that quartz overgrowths have a complex growth history. Previous workers (Kraishan et al. 2000) suggested that CL patterns in quartz cement are largely due to trace elements rather than defects and that aluminum varies consistently between each cement phase. Electron Backscatter Diffraction (EBSD) combined with Wavelength Dispersive Spectrometry (WDS) confirms that the complex banding visible in CL is not due to changes in crystallographic orientation but more likely variations in quartz composition associated with changes in pore fluid composition and/or reservoir conditions. Secondary Ion Mass Spectrometry (SIMS) analysis provides maps of ultra-trace element distribution that confirm that trace amounts of iron, manganese, and titanium can be used as proxies for defect density and temperature. Additionally, SIMS analysis provides oxygen isotope data providing insight into the initial reservoir conditions and temperature of formation of microcrystalline quartz in several formations.
Microcrystalline quartz in the form of replacement, micropore, and overgrowth cements is present in the Wolfcamp A in the southern Delaware Basin. The amount of cementation has an effect on the reservoir quality and appears to have an impact on the petrophysical properties. The siliceous mudstones are comprised predominantly of biogenic silica (sponge spicules, radiolarians, which are the silica sources for the authigenic microcrystalline quartz), detrital grains (quartz and feldspars), pyrite framboids, and organic matter.
Integrating the results from these advanced analytical techniques has helped us develop our understanding of the processes controlling the formation of quartz cement and improved our ability to reconstruct the reservoir diagenetic history of quartz growth leading to a proposed model for predicting porosity preservation in deep, hot sandstone reservoirs and the formation of microcrystalline quartz in siliceous mudstones. This is the first research to report on spatially resolved isotopic analysis of silica cements integrated into a petrographic framework and a proposed mechanism for microcrystalline quartz growth.
Reservoir simulation is a widely used tool for making decisions on the development of new fields, the location of infill wells, and the implementation of enhanced recovery projects. It is the focal point of an integrated effort of geosciences, petrophysics, reservoir, production and facilities engineering, computer science, and economics. Geoscientists using seismic, well-log, outcrop analog data and mathematical models are able to develop geological models containing millions of cells. Simulation of the reservoir at the fine geologic scale, however, is usually not undertaken except in limited cases. Generally, the fine-scaled geological model is partially integrated or "upscaled" to a coarse-grid model, which is computationally more tractable.
Tong, Fangchao (Yanchang Petroleum) | Tang, Mingming (Yanchang Petroleum) | Chen, Gang (Yanchang Petroleum) | Wang, Ningbo (Yanchang Petroleum) | Liu, Peng (Schlumberger) | Yan, Gongrui (Schlumberger) | Lin, Wei (Schlumberger)
Drilling horizontal wells in YB gas field in Ordos Basin presents significant challenges due to severe wellbore instabilities problems in drilling through Permian Lower Shihezi and Upper Shanxi formations, where laminated shales overlies with sand and coal seam. In first phase of horizontal wells drilling, most wells encountered severe wellbore instabilities including pack-off, stuck-pipe, over-pull, drilling pipe lost in hole and even side track. Post-well analysis showed that these horizontal wells instabilities mainly occurred in Permian Lower Shihezi and Upper Shanxi formation where most cavings and drilling events (stuck-pipe, over-pull) were observed. In contrast, vertical exploration wells have no such instability issues in same interval. To analyze and understand the mechanism of wellbore instability issue and provide optimal mud weight and better drilling practice to reduce the risk of wellbore instabilities, an anisotropic wellbore stability modeling using Plane-of-Weakness (PoW) failure criterion was carried out in this study. The PoW failure criterion is adopted to compute the onset of rock shear sliding and/or fracture along a weak plane (bedding or fracture) and identify the potential wellbore instability risk in drilling through anisotropic rock formations. The influence of bedding orientation, rock anisotropic elastic and strength properties, and wellbore trajectory on the wellbore stability are all included in the model.
This paper describes the process and workflow of conducting PoW wellbore stability modeling for YB field wellbore drilling. The proposed drilling parameters (stable mud weight) from the modeling and its application and improvement for next wells drilling, are also included. The analysis showed that the laminated shale and coal intervals were very prone to fail when well drilled with deviation between 600 to 850. The stable mud weight computed from PoW for drilling through these intervals is 1.40-1.45 g/cc, where as it is 1.20-1.25 g/cc from conventional isotropy wellbore stability model, which was not enough to keep wellbore stable. Based on results from PoW modeling, drilling mud weight scheme was updated and applied to another 3 horizontal wells planned at nearby location. All these three wells were drilled and completed safely without severe wellbore instability issue. In these wells’ 216mm (8.5 in) section, wellbore instability related non-productive time (NPT) was reduced about 11.5 days per well and section time was reduced about 26 days per well.
This PoW modeling was first time applied in wellbore stability analysis for horizontal well drilling at Ordos Basin and the results are satisfied and encouraged. The insights provided in this paper suggests that, for drilling in other locations with similar instability challenges, PoW modeling will be a better choice to provide solution and recommendation to ensure drilling safely, improve drilling efficiency and reduce drilling costs.
Building realistic and reliable subsurface models requires detailed knowledge of both the rock and fluids involved. While the hydrocarbon volume estimation has a profound impact on the viability of a development, next to the saturation height models and free fluid levels the hydraulic communication and permeability have a significant role as well. Compartmentalization could change the field development plan: e.g. increase the well count, necessitate significant change to the well profiles (e.g. extended range drilling), require complex and expensive completion strategy.
When in different parts of the same field different free fluid levels are identified, leading to different fluid contacts for the same rock quality, the lateral hydraulic communication at the field level can be challenged. This aspect is of importance since the hydrocarbon volume distribution has drastic impact on total hydrocarbon recovery. At the same time building and initializing a model based on different free water level positions across the field, zero capillary pressure, is challenging.
Perched water contacts are the result of water entrapment during the hydrocarbon migration that could lead to variability in free fluid levels across a field. The fundamental controls that lead to the perched contacts formation are studied and shown to be the rock quality and relative permeability. Counter-intuitively, the perching effect is not going to feature in poor quality rocks with sub-milli Darcy permeability – the effects would be visible only for a considerable barrier height, with Free Water Level to barrier height of tensto hundred meters.
In addition, realistic heterogeneous models are studied to investigate the heterogeneity effect on perching and on formation pressures. Whilst low permeability is correlated to a wide range of depths where two phases are mobile, the perching controls in high permeability contrast formations are studied.
Using a dynamic modelling route, potential water entrapment occurrence as a result of high permeability contrast is shown, without structural control, i.e. an underlying impermeably zone defining a trap. The main control in such a case is water permeability just as in structurally controlled perching. This work challenges the industry view that model initialization should be performed with buoyancy as an equilibrium driving mechanism. Such a saturation modelling route would lead to discrepancies when compared to using the capillary pressure as a direct input instead of buoyancy.