With a global paradigm shift towards exploring shale reservoirs, the industry focus has moved towards optimizing hydraulic fracturing in these reservoir types. Low-viscosity slickwater fracture treatments are commonly used as a completion technique in these ultra-low permeability reservoirs. Each shale reservoir is different due to the presence of in situ natural fractures and other geologic complexities, and thus the resultant hydraulic fracture network is distinct and the proppant transport in these "created" complex fracture networks is not clearly understood. Much speculation exists in the industry as to how efficiently the proppant is transported from the primary fracture into subsidiary fractures, if it is at all. A better awareness of proppant movement in complex fracture networks can possibly help with better hydraulic fracture treatment designs by focusing on parameters that enhance transport in the subsidiary fractures and understanding what impacts this transport may have on the resulting production. This paper discusses a series of tests carried out in a low-pressure laboratory setting to evaluate proppant transport in complex fracture networks. Different slickwater treatment scenarios were simulated by pumping sand slurry through a series of complex slot configurations while varying the slot complexity, pump rate, proppant concentration, and proppant size. Results from twenty-seven tests carried out provide some interesting insights into the nature of proppant transport and settling in complex fracture networks. In the case of a primary slot system, the proppant transport was observed to occur via traction carpet after the creation of a proppant dune. However, in the case of secondary slots, the proppant transport was found to be dependent on the dune buildup in the primary slot. Two mechanisms were observed to be transporting the proppant into the secondary slots: 1) proppant flowing around the corner at pump rates higher than the threshold pump rate (related to the threshold velocity in the primary slot), and 2) proppant falling from the primary slot due to the effects of gravity, regardless of the pump rate.

This paper presents the results of an integrated laboratory and numerical modelling study on the effect of wellbore deviation and wellbore azimuth on fracture propagation in poorly consolidated sandstone formations. The goal of this project was to develop an understanding of how fractures would transition from single planar fractures to non-planar transverse fractures for fields in the deep-water Gulf of Mexico.The foundation of this work was over 40 fracturing laboratory tests to measure fracture propagation geometries for a range of well deviations, differential horizontal stresses and rock strength. The samples tested were from three outcrops with unconfined compressive strength (UCS) values ranging from 300 -1000 psi. For boreholes having low deviation angles and small differential stresses a vertical single planar fracture was created, aligned with the wellbore, as expected. As the well trajectory and stress contrast increased the fractures became more complex, with transverse turning fractures no-longer aligned with the wellbore.These laboratory results were used to develop and calibrate a new fully-3D finite element model that predicts non-planar fracture growth. The model matches the details of the laboratory tests, including the transition from planar vertical to nonplanar transverse fractures as the well deviation, azimuth and stress differentials increase. After initial model development and calibration was complete a model of a complex case was run before showing any experimental results to the modellers. The model successfully predicted the transverse non-planar results found in the laboratory; this gave us increased confidence in the model as a predictive tool. This work has now been applied with excellent success to four deepwater fields. We have recommended changes in maximum well deviations, performed post-job analyses on wells that had high deviations, and have increased our understanding of the impact of layered formations on fracture growth in these fields.

Proppant fractures along the horizontal laterals in the Valhall Field have become a standard completion method for the last eight years with over 150 proppant fractures completed to date. The development of the flank regions of the Valhall Field began, with the first of 14 wells completions, in March 2003. Lateral lengths of up 2,000 meters will be drilled from two new platforms placed on the North and South edges of the field. The chalk formation in the flank regions is expected to be more competent then the crestal part of the field, so the question was raised as to whether fracturing should be done with acid or proppant. From a proppant fracturing perspective, each flank well will require between 10 to 14 prop fractures along its lateral requiring 2.5–3.7 Million pounds of proppant per well. Three different methods have been used to determine whether the wells should be acid or proppant fractured. These consist of reviewing the historical well performance, analytical and numerical modeling. All three methods clearly showed proppant fracturing was the preferred stimulation for the Valhall Field regardless of it's location. Acid fracturing becomes the stimulation of choice only if the well does not come in contact with enough OOIP (e.g. 5 MMSTB) to justify the proppant fractures. Proppant fracturing is expensive, so in conjunction with identifying the best stimulation method for the flank region, optimization with respect to fracture spacing along the horizontal lateral, fracture length and width have been numerically modeled for both the crestal and flank wells. This is an evolving process that should be considered an industry "Best Practice" as it enables real time optimization of ‘prop’ fracturing along a horizontal lateral during the drilling and completion phase. Since the start of this "Best Practice" in 2002, the wells stimulated in the crestal part of the Valhall Field have had the highest productivity in the field's history. Introduction The Valhall Field is an Upper Cretaceous, asymmetric chalk anticline that forms an overpressured, under-saturated, oil reservoir located in the Norwegian sector of the North Sea (Figure-1). It is characterized by high porosity (25–48%) and high oil saturation (92–97%). In common with other chalk reservoirs in the region, the drive mechanism is a combination of fluid expansion and formation compaction. The production is mainly from the high porosity (35–48%) Tor formation, which exhibits typical thickness of 15–40 m and a permeability of 1–10 mD. The source rock is the organically rich Kimmeridigian Clay underlying the chalk and has resulted in a reservoir, which is over pressured for depth with an undepleted gradient of 0.78 psi/ft TD at 2,500 mTVD1. The field will recover over 1 billion STB with current production of 80,000 BOPD from 42 wells on the main Drilling Platform and the Wellhead Platform (WP), which are centrally located in the crestal part of the field. The field was originally sanctioned and placed on production back in 1982 with reserve estimates of only 250 MMSTB. Reserves have increased by 400% since then throughbetter reservoir description,improving the completions and drilling strategy from vertical indirect proppant fractures to long horizontals with multiple proppant fractures, andthe current development of the flank areas of the field and the initiation of a waterflood in the crestal section.

Since 2004 Southwestern Energy (SWN) has completed more than 2,000 wells in the Fayetteville shale with thousands of wells remaining to be drilled and completed. The Fayetteville is a world-class shale play stretching across central Arkansas that encompasses more than 2-million acres. Current SWN gross daily operated production is more than 1.9 BCF/D and at December 31, 2010 its proved net reserves booked in the Fayetteville were 4.3 TCF. This paper will discuss the progression of the completions from the beginning to their current best practices. It will review the different types of completions, stimulation optimization, high efficiency operations, and well performance.

Fracture conductivity in shale is largely dependent upon the shale rock properties and the formation conditions. This paper aims to explore two different vertical intervals of the Fayetteville Shale, FL2 and FL3, by comparing laboratory fracture conductivity measurements. Fayetteville Shale outcrop cores were artificially fractured, preserving the surface roughness for the conductivity measurements. Controllable parameters, such as proppant size, concentration and type, were kept consistent between the two zones. An initial unpropped experiment was run, followed by two 30:70 mesh propped experiments at 0.03 lb/ft 2 and 0.1 lb/ft 2 concentrations.The FL2 consistently recorded higher conductivity values than the FL3 at closure stress up to 3, 000 psi. Therefore, each zone was evaluated using mineralogical composition, thin-section analysis and surface-roughness scans to identify rock property differences. The FL2 and FL3 rock analysis identified that the two zones are very different. Although the FL2 and FL3 samples used in the conductivity experiments had similar clay content, the FL2 contained more quartz and the FL3 contained more carbonate. Additionally, the FL2 samples were less fissile and had larger surface fragments break along the fracture surface, whereas the FL3 samples broke parallel to the bedding plane and had flaky dust fragments break along the fracture surface. The FL2 had higher conductivity values at low closure stress due to the rearrangement of bulky surface fragments and larger voids created on the surface when fragments were lost. The difference between the FL2 and FL3 conductivity decreases as the concentration of proppant increases because the voids causing unpropped conductivity differences become filled with proppant. Finally, production data was used to confirm laboratory results by providing evidence that wells in the FL3 produce less than the wells in the FL2 formation.