Smith and Hannah[1] documented the evolution of hydraulic fracturing in high-permeability reservoirs since the 1950s. The first fracture treatments in the 1950s were pumped in moderate- to high-permeability formations. Those treatments were designed to remove formation damage that usually occurred during the drilling and completion operations. Low-permeability reservoirs were fracture treated in the 1950s and 1960s, but, at low oil and gas prices, low-permeability reservoirs were generally not economic, even after a successful fracture treatment. The values of high, moderate, and low permeability need to be defined on the basis of both the formation permeability and the reservoir fluid viscosity, or the k/μ ratio, where k is the formation permeability in md, and μ is the formation fluid viscosity in cp.

Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.

Summary Late in the life of the Steam Assisted Gravity Drainage (SAGD) process, it has become common practice to drill a single, horizontal infill well (called a “Wedge Well™” by some) in the oil bank located between two mature SAGD well pairs to produce the bitumen that has been heated and mobilized but is unable to be effectively drained by gravity given the largely lateral location relative to that of the SAGD producers. Since this oil bank is surrounded by the large, depleted steam chamber created by the existing well pairs, it requires little heat to mobilize bitumen. One of the challenges, however, in producing infill wells is that non-uniform drainage and local hot spots can be readily created in the first year of their operation, that in many cases require completion retrofits, such as with Flow Control Devices (FCDs), to improve the drainage profile. Installation of FCDs in these wells is quite challenging since the dynamics of the infill wells is changing with time and there is limited time to achieve conformance. To maintain pressure in SAGD chambers the common practice is to inject non-condensable gas (NCG). NCGs, such as methane, which is most common, do not condense in the steam chamber. Some of these NCG can short-cut into the infill through the existing hot-spot. The main reason is that the hot sections of infills are locations that are closer to the SAGD steam chamber, and due to steam condensate encroachment and higher mobility create a pathway for NCG breakthrough. FCDs are designed to promote a more uniform flux distribution along the producer, and exposure to NCG can change the impact of the FCDs. The true hot-spot temperature after NCG injection is decreasing and this can be mistaken as FCD efficiency and steam blocking. In reality, this temperature reduction is due to partial pressure effects associated with NCG encroachment. In this study, a new thermodynamic model is created to explain the NCG encroachment into infill wells, and a new temperature profile along the producer as a function of NCG breakthrough is calculated. The purpose of this work is to create a productivity index (PI) relationship that is fit for purpose for infill wells adjacent to SAGD well-pairs with NCG breakthrough that can primarily be used for analysis and optimization of SAGD FCD completions. This model can also be used to evaluate FCD performance in infill wells pre- and post- NCG breakthrough.

One of the grand challenges facing the oil and gas industry's global quest to improve the potential of tight reservoirs involves designing horizontal-well completions that match the often-complex heterogeneity of the target formations. This sums up the general concept most call the "engineered completion." In theory, tailoring a stimulation job to the varying rock properties found along the lateral section of a horizontal wellbore should result in better production for less capital. In practice, the industry has never attempted to do this on a meaningful scale. Among other reasons, the detailed subsurface data required to shake the bonds of geometric, or "cookie cutter," designs have long been considered too costly to gather or too time-consuming to analyze.

One of the grand challenges facing the oil and gas industry's global quest to improve the potential of tight reservoirs involves designing horizontal-well completions that match the often-complex heterogeneity of the target formations. This sums up the general concept most call the "engineered completion." In theory, tailoring a stimulation job to the varying rock properties found along the lateral section of a horizontal wellbore should result in better production for less capital. In practice, the industry has never attempted to do this on a meaningful scale. Among other reasons, the detailed subsurface data required to shake the bonds of geometric, or "cookie cutter," designs have long been considered too costly to gather or too time-consuming to analyze.

Introduction The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field.[1] Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping a fluid into a wellbore at an injection rate that is too great for the formation to accept in a radial flow pattern. As the resistance to flow in the formation increases, the pressure in the wellbore increases to a value that exceeds the breakdown pressure of the formation open to the wellbore. Once the formation "breaks down," a fracture is formed, and the injected fluid begins moving down the fracture. In most formations, a single, vertical fracture is created that propagates in two directions from the wellbore. These fracture "wings" are 180 apart and normally are assumed to be identical in shape and size at any point in time; however, in actual cases, the fracture wing dimensions may not be identical. In naturally fractured or cleated formations, it is possible that multiple fractures can be created and propagated during a hydraulic fracture treatment. Fluid that does not contain any propping agent (called the "pad") is injected to create a fracture that grows up, out, and down, and creates a fracture that is wide enough to accept a propping agent. The purpose of the propping agent is to prop open the fracture once the pumping operation ceases, the pressure in the fracture decreases, and the fracture closes.

There are many factors that the engineer must consider when analyzing the behavior of a well after it has been fracture treated. The engineer should analyze the productivity index of the well both before and after the fracture treatment. Other factors of importance are ultimate oil and gas recovery and calculations to determine the propped fracture length, the fracture conductivity, and the drainage area of the well. Post-fracture treatment analyses of the fracture treatment data, the production data, and the pressure data can be very complicated and time consuming. However, without adequate post-fracture evaluation, it will be impossible to continue the fracture treatment optimization process on subsequent wells. Many of the early treatments in the 1950s were designed to increase the productivity index of damaged wells.

There are two fundamental problems that make accurately estimating the productivity of a horizontal well more difficult than estimating the productivity of a vertical well. The theoretical models available have a number of simplifying assumptions and the data required for even these simplified models are not likely to be available. Still, we must make estimates and decisions based on those estimates. In this page, two productivity models that have proved useful in practice are discussed. The first, published by Babu and Odeh[1] in 1989, is limited to single-horizontal wells.

When temperature logs are run in SAGD producers, temperature variations of greater than 50 C between the hottest and coldest spots are commonly observed. The authors theorize that this temperature distribution is related to an inflow distribution and that production rates could be improved if this temperature variance was narrowed. The Firebag project in northeastern Alberta uses SAGD to recover bitumen from the McMurray formation. SAGD uses stacked horizontal-well pairs, with the top well (injector) located 4 to 6 m above the bottom well (producer). Steam is injected into the top well, warming the bitumen and decreasing its viscosity to a point at which it will flow by gravity to the bottom well.

Multilateral wells with smart completions controlled by different flow-control technologies offer great operational flexibility, with each lateral able to be operated and optimized independently. Understanding the contribution of each lateral in the complexity of the system was a major objective of this study. In order to optimize the system and predict results under different operational conditions, a multilateral-well-modeling methodology was developed. This methodology covers two main factors affecting multilateral productivity--a flow-dependent gas/oil ratio (GOR) and interference between the laterals. The study was based on multilateral wells complete with inflow control valves (ICVs).