|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
A complete fluid mechanics analysis of wellbore flow solves the equations of mass, momentum, and energy for each flow stream and the energy equation for the wellbore and formation. Static wellbore pressure solutions are the easiest to determine and are the most suitable for hand calculation. Because velocity is zero and no time dependent effects are present, we need only consider Eq. 1 with velocity terms deleted. Temperatures are assumed to be static (often the undisturbed geothermal temperature) and known functions of measured depth. The simplest version of Eq. 2 is the case of an incompressible fluid with constant density ρ.
The definition of a tight gas reservoir is that the reservoir does not produce at commercial gas flow rates, or recover commercial volumes of natural gas, unless a hydraulic-fracture treatment is properly designed and pumped. As such, the entire drilling and completion procedures should focus on making sure the optimum fracture treatment can be designed and pumped in the field. When drilling a tight gas well, the most important aspect of the drilling operation is to drill a gauge hole. Many times this means the well should be drilled at a balanced mud weight or slightly overbalanced. In other cases, air drilling or underbalanced drilling works best, as long as the hole remains in gauge.
This page provides SPE members access to the June 2021 issue -- digital, pdf, and online. Digital archive of issues back to January 2020 is available – scroll down from the current issue cover. These are the papers synopsized in JPT this month. They are available to SPE members only through 31 July 2021. There are also links to them at the bottom of each related synopsis.
The reservoir upon which this case study is focused is a tight, low-permeability carbonate reservoir with thin layers. The objective of the field case was to increase and sustain productivity of a pilot well consisting of an openhole completion. The complete paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. The study may provide a potential approach for selecting the proper hydraulic fracturing method and technique in similar cases. Reservoir X is divided into six layers.
Using natural-gas (NG) -foam fracturing fluids reduces the enormous water requirements for stimulation by as much as 60 to 80% and poses benefits for productivity in water-sensitive formations. The study outlined in the complete paper aims to characterize hydraulic-fracture geometry and quantify the expected production when using an NG-foam fracturing fluid. Using validated models, the authors provide a comparative analysis to determine the advantages of using NG foams relative to conventionally used slickwater, linear gel, and crosslinked fluid. Although foamed fluids were first used in the 1960s, the use of nitrogen (N2) and carbon dioxide (CO2) foams has not been widely practiced because of cost, complexity, and unproven production benefits. The use of NG-foam fracturing fluid is not widespread either, but this study attempts to identify specific regions and reservoirs where the use of these fluids may lead to economic and long-term production benefits.
The complete paper presents recent results from a rigorous pilot-scale demonstration of natural-gas (NG) foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The NG foams explored in these investigations exhibited typical shear-thinning behavior observed in rheological studies of nitrogen- (N2) and carbon-dioxide- (CO2) based foams. The measured viscosity and observed stability indicate that NG foams are well-suited for fracturing applications. Two test facilities were used to explore properties of NG foams at a variety of relevant operating conditions to determine whether NG foam is a suitable alternative to typical water-based fracturing fluids. The pilot-scale foam-test facility (PFTF) is a single-pass pilot plant used to generate and characterize foams at conditions relevant to surface and reservoir conditions.
This issue marks the debut of the Hydraulic Fracturing Operations feature in JPT. While hydraulic fracturing has long been a feature topic, this year, we are branching this major area of interest into both this feature and a Hydraulic Fracturing Modeling feature, which will appear in the November issue of the magazine. For this issue, reviewer Nabila Lazreq of ADNOC has selected three papers that reflect industry efforts to achieve new goals in production and sustainability. Paper 201450 investigates the potential of natural gas (NG) foam fracturing fluid to reduce the major water requirements seen in stimulation. The authors write that such requirements can be reduced up to 80% in some cases by the use of NG foams.
This paper presents a case study of fracture interaction mitigation in a multistage horizontal stimulation of an offshore Black Sea well. The authors discuss a multifaceted approach in applying lessons learned and pre-job geomechanical analysis of depletion-induced stress differential and its effects on fracture interactions. Intrastage fracture interference presents unique challenges that typically are managed on a case-by-case basis. This study aims to present critical analyses that are paramount to planning stimulation treatments in highly depleted segments and reservoirs with close-proximity wells. The operating company began a field redevelopment project in 2013 for a field in the Black Sea that was already producing from horizontal wells with multistaged fractured wells.
In earlier days, the main technology developments were mostly related to the materials, such as fluids and proppants, and their characterizations. In recent years, more advancements have been made in tools, engineering processes, and analyses. In a cased-hole fracturing treatment, perforating plays a critical role to the success of the job, though it is often overlooked because perforations are visualized as holes with empty tunnel behind the pipe. Any damage is irrelevant because fracturing will simply bypass the damage. In fact, a shaped charge is made of metal liner and case with explosive loaded in between.
The onset of erosion of coiled tubing (CT) strings may be difficult to predict in annular fracturing operations. The complete paper describes a methodology of verifying that CT strings have not been subject to erosion caused by annular fracturing operations. An exploration of pumping rates used on these strings in operations also provides field-tested practical guidelines for avoiding erosion when performing annular fracturing jobs. A CT string may be exposed to erosion in the outer surface during CT annular fracturing operations. The critical parameters that may influence the magnitude of erosion include fracturing pump rate, sand concentration, fluid rheology, wellbore geometry, and the grade of CT string.