Refracturing

Fracture conductivity is directly affected by an uneven proppant distribution, which affects the productivity of a well. The distributions of 40/70 mesh white sand compared to 100 mesh brown sand in a horizontal wellbore were investigated in this study. The apparatus used to conduct these tests was a 30 ft-long transparent horizontal wellbore with three perforation clusters. The proppant distribution was examined experimentally by injecting slurries at three different injection rates ranging from 20 to 75 gpm. The proppant concentration of both sands increased for each test from 0.5 to 2 ppg. The proppant concentrations and injection rates were used with multiple perforation configurations (orientations) including extreme limited entry perforations. The results confirmed that the injection rates significantly affected the proppant distributions across the different perforation clusters. Even distribution of the 40/70 mesh sand can be obtained using a 1 shot per foot (SPF) top perforation design. The 100 mesh sand was evenly distributed using a 4 SPF perforation configuration. The settling percentage was calculated for each experiment to determine the quantity of 40/70 mesh and 100 mesh sand settled at the bottom of the horizontal wellbore. A carrier fluid can suspend the sand more effectively with a higher injection rate, reducing the average sand settling to 2% in the case of the 100 mesh sand compared with approximately 8% for the 40/70 mesh sand at similar injection rates. This research confirms the need to use a 100 mesh at high injection rates to reduce sand settling during the hydraulic fracturing process.

Section: Introductionmentioning

confidence: 99%

Experimental Investigation of the Impact of Particle Size on Its Distribution within a Horizontal Wellbore

Alajmei,

Budiman,

Aljawad

2023

“…Over the past seven decades, improvements in fracturing technology and techniques have allowed for significant increases in production, especially in low-permeability reservoirs and source rocks. 1 During fracturing, the requirements for proppant transport and fracture propagation are inherently at odds with one another. The length and complexity of the fracture network and the transport of the proppant inside the network must be simultaneously optimized for obtaining the best fracturing results.…”

Section: ■ Introductionmentioning

confidence: 99%

“…Since its viability as a technique for extracting hydrocarbons was first recognized in the mid-1940s, hydraulic fracturing has become an industry standard. Over the past seven decades, improvements in fracturing technology and techniques have allowed for significant increases in production, especially in low-permeability reservoirs and source rocks …”

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Seawater-Based Fracturing Fluid: A Review

Budiman,

Alajmei

2023

Hydraulic fracturing uses a large amount of fresh water for its operation; conventional wells can consume up to 200 000 gallons of water, while unconventional wells could consume up to 16 million gallons. However, the world's fresh water supply is rapidly depleting, making this a critical and growing problem. Freshwater shortages during large-scale hydraulic fracturing in regions that lack water, such as the Arabian Peninsula and offshore operations, need to be addressed. One of the ways to address this problem is to substitute fresh water with seawater, which is a sustainable, cheap, and technically sufficient fluid that can be utilized as a fracturing fluid. However, its high salinity caused by the multitude of ions in it could induce several problems, such as scaling and precipitation. This, in turn, could potentially affect the viscosity and rheology of the fluid. There are a variety of additives that can be used to lessen the effects of the various ions found in seawater. This review explains the mechanisms of different additives (e.g., polymers, surfactants, chelating agents, cross-linkers, scale inhibitors, gel stabilizers, and foams), how they interact with seawater, and the related implications in order to address the above challenges and develop a sustainable and compatible seawater-based fracturing fluid. This review also describes several previous technologies and works that have treated seawater in order to produce a fluid that is stable at higher temperatures, that has a considerably reduced scaling propensity, and that has utilized a stable polymer network to efficiently carry proppant downhole. In addition, some of these previous works included field testing to evaluate the performance of the seawater-based fracturing fluid.

“…There are many factors affecting fracture height propagation in multilayer formations, mainly including geological factors (e.g., natural fracture, rock mechanics parameters (e.g., shear modulus, fracture toughness, shear strength, tensile strength, and Poisson’s ratio), in situ stress, and layer interface) and engineering factors (e.g., working fluid properties (e.g., fluid density, viscosity, and filtration), induced stress caused by other artificial fractures, and construction parameters (e.g., injection displacement, pressure, and fluid volume)). Researchers have done a series of work on the influence of these factors for decades and achieved remarkable results. − …”

Section: Introductionmentioning

confidence: 99%

Numerical Modeling of Fracture Height Propagation in Multilayer Formations Considering the Plastic Zone and Induced Stress

Chen

Liu

et al. 2022

Hydraulic fracturing and acid fracturing are very effective stimulation technologies and are widely used in unconventional reservoir development. Fracture height, as an essential parameter to describe the geometric size of a fracture, is not only the input parameter of two-dimensional fracturing models but also the output parameter of three-dimensional fracturing models. Accurate prediction of fracture height growth can effectively avoid some risks. For example, petroleum reservoirs produce a large amount of formation water because wrong fracture height prediction leads to the connection between the oil or gas reservoir and the water layer. Although some fracture height prediction models were developed, few models considered the effects of the plastic zone, induced stress, and heterogeneous multilayer formation and its interaction. Therefore, considering the influence of many factors, an improved fracture-equilibrium-height model was developed in this study. The successive over-relaxation iteration method and the displacement discontinuity method were used to solve the model. We investigated the effects of the geological and engineering factors on fracture height growth by using the model, and some important conclusions were obtained. The higher the fracture height, the larger the plastic zone size, and the more obvious its influence on fracture height propagation. High overlying or underlying in situ stress and fracture toughness and low fluid density played a positive role in limiting the growth of the fracture height. Induced stress caused by fracture 1 could not only inhibit the height growth of fracture 2 but also promote its growth. The model established in this paper could be coupled to a fracturing simulator to provide a more reliable fracture height prediction.