"Super Height Growth" —Strange Surface Pressures and Refrac Potential

A database has been compiled and analyzed, summarizing more than 100 field studies in which restimulation treatments (hydraulic refracs) have been performed, along with the production results. Field results demonstrate that refrac success can be attributed to many mechanisms, including: – Enlarged fracture geometry, enhancing reservoir contact – Improved pay coverage through increased fracture height in vertical wells – More thorough lateral coverage in horizontal wells or initiation of more transverse fractures – Increased fracture conductivity compared to initial frac – Restoration of fracture conductivity lost due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. – Increased conductivity in previously unpropped or inadequately propped portions of fracture – Improved production profile in well; preferentially stimulating lower permeability intervals [reservoir management] – Use of more suitable fracturing fluids – Re-energizing or re-inflating natural fissures – Reorientation due to stress field alterations, leading to contact of "new" rock Although less frequently published, unsuccessful restimulation treatments are also common. Documented concerns illustrated in this paper include: – Low pressured, depleted wells (especially gas wells) posing challenges with recovery of fracturing fluids – Low pressured or fault-isolated wells with limited reserves – Wells in which diagnostics indicate effective initial fractures and drainage to reservoir boundaries – Wells with undesirable existing perforations, or uncertain mechanical integrity of tubing, casing, or cement This paper will explore the common problems that lead to unsatisfactory stimulation, or initial treatments that fail over time. Guidelines for evaluating refrac candidates and improving initial treatments will be reviewed. The paper summarizes restimulation attempts in oil and gas wells in sandstone, carbonate, shale and coal formations. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.

Refracs: Why Do They Work, and Why Do They Fail in 100 Published Field Studies?

Vincent

2010

The Design and Execution of Frac Jobs in the Ultra Deepwater Lower Tertiary Wilcox Formation

Haddad¹,

Smith²,

Moraes

et al. 2011

A considerable amount of effort goes into designing one of the deepest frac jobs in the world. For the past several years, Petrobras has been working on developing the Cascade and Chinook fields which are located in the Gulf of Mexico (GOM), 250 miles south of New Orleans in ultra deepwater depths between 8200 ft and 8900 ft. The oil producing reservoir is in the Lower Tertiary Wilcox formation with a gross sand thickness of 1200 ft. The reservoir mid-point is at an average depth of 25, 600’ TVD with a bottomhole pressure of 19, 500 psi and a bottomhole temperature of 260°F. The reservoir is comprised of vertically stacked thin beds of sand and fine grained siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in a paper written by Moraes el al (2010). Multiple limitations were considered during the initial design phase of the frac pack program. The fracs were designed taking into account the use of a Single-Trip Multi-Zone sand control system. Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operation stand point due to a continuous, multi-stage frac operation. Some of the operation limitations included service tool erosion limitations due to maximum pump rates and proppant volumes, overall frac vessel capacity, boat-to-boat fluid transfers and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, comply with tool spacing limitations and still maximize contact with net pay. This paper addresses the approach taken to develop a fracture stimulation program for the Lower Tertiary formation in the Cascade and Chinook fields. Some of the major questions addressed during this process include the following: how many fracture treatments are needed, what is the optimum fracture geometry, what is the desired conductivity, how to effectively position the perforation intervals, what is the desired pump rate and is a high-density fluid needed to fracture this deep, high-pressure formation? The approach, the answers and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations. Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (due to depth and in-situ stresses) where fracturing is required for both stimulation and potential formation collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.

Quantifying and Mitigating the Impact of Asymmetric Induced Hydraulic Fracturing from Horizontal Development Wellbores

Walser

Siddiqui

2016

Sufficient production and fracture mapping evidence across North America is now available to clearly demonstrate that pairs of delineation and development wells often underperform when there is substantial production time (months or years) between the completions of the two wells. The relative degree of impact on hydrocarbon extraction per acre varies from one play or formation to another, but the phenomena is generally attributed to asymmetric induced fracturing from the development (child) well into the previously partially drained and lower static pressure delineation (parent) well reservoir volume. This paper briefly discusses two solutions that have been employed to minimize the negative fiscal ramifications and improve recovery. Rigorous 3D unstructured grid reservoir modeling can assist in the quantification of the phenomena; however, options for mitigating the problem for cases where the impact is extreme are typically limited. Synthetic history matching and forward modeling were performed with a grid-based numerical simulator that mimicked a series of asymmetric oblique fractures interacting with a drained reservoir volume, comparing acceleration of reserve recovery and total recovered reserves with a similar case involving symmetric fracturing. Two scenarios for preventing extreme asymmetric fracturing are discussed. These included dramatic shortening of the time between completions, and performing pressure sink mitigation (PSM) via refracturing of the delineation wellbore. It is shown that the asymmetric fracturing into drained volumes can materially impact reserves and rate of recovery if the acreage position of a given project is substantial. It is demonstrated that the overall stimulated reservoir system permeability, the degree of permeability contrast between reservoir layers, and the degree of asymmetry are all factors that have an impact on the degree to which the long-term time between completions affects recovery of hydrocarbons over and above simple volumetric depletion. Integration of rigorous 3D reservoir modeling and far-field fracture mapping have established that the negative ramifications of extreme induced fracture asymmetry can be overcome with careful application of drilling and completion (D&C) timing and offset drainage pressure management process.