The objective of hydraulic fracturing is to design and execute a fracture stimulation treatment that achieves the desired fracture dimensions (length and conductivity) to maximize a wells production rate and reserve recovery. To achieve this objective, there are several critical parameters to the process, and these fall into two distinct categories:parameters over which we have little control, but need to understand, andthose that we control, but have lesser impact on the process. The first category includes fracture height, fluid loss coefficient, tip effects, and Young's modulus. The second category includes pump rate and fluid viscosity. Of the former parameters, Young's Modulus is the only variable that can be measured, in advance, via lab tests. Traditionally, Young's Modulus is measured through stress-strain testing of geologic samples (core plugs) which always demanded an L/d (Length/ diameter) ration of at least 2:1. The reason for this criterion is that the ultimate failure mechanism for most rocks under compression loads is the formation of a shear fracture. For most rock types, this shear fracture will form at an angle of about 30° from the axis of the maximum compression load. Thus, a 2:1 L/d ratio allows a through-going shear fracture to form for a failure angle of 30°. For stress-strain testing NOT concerned with ultimate failure of the sample, this valid criterion has always been followed - arbitrarily and artificially. Unfortunately, this sample criterion generally eliminates the use of sidewall cores. This paper details and documents an evaluation of the Length to diameter criteria through finite element modeling, tri-axial compression testing of aluminum, and compression testing of actual sedimentary rock samples. Through this work, it is evident that core samples of L/d significantly less than 2:1 can provide reliable values of static Young's Modulus. Further, these results indicate that rotary sidewall cores can be utilized to determine Young's Modulus in many applications provided adequate sample quality assurance is undertaken to ensure sample integrity. Introduction Determination of mechanical rock properties is important to the oil and gas industry for reservoir compaction, borehole stability, formation control, and hydraulic fracturing. Measurements of the elastic rock properties have historically been conducted on whole core and via wireline measurements once the wellbore has been drilled. Application of these methods at the well site in real time on drill cuttings and with Measurement While Drilling (MWD) to improve or optimize the drilling process is the focus of much ongoing research1–5. Studies by Ringstad et al2, Zausa et al3, and Santarelli et al4 evaluated the use of drill cuttings for mechanical properties determination. Because of this, these studies focused on sample size sensitivities and determined that the micro indentation measurements correlated well to Uniaxial Compressive Strength of the rock. However, these measurements correlated poorly with Young's Modulus or porosity. Similarly, Nes et al5 investigated sample size sensitivities on both the static and dynamic behavior of the Pierre Shale. This study evaluated the elastic properties of 0.39 inch diameter samples 0.16 inches in length (L/d = 0.4) and found that the static Young's Moduli of the "hard" shale samples was in excellent agreement (i.e. within 3.5 %) with larger sized core plugs. The static Young's Moduli of the soft shale samples tested were in much poorer agreement (i.e. nearly a 20 % error) as compared to larger sized samples tested. Finally, this work showed excellent agreement (i.e. +/− 2 %) between the dynamic moduli determined with a Continuous Wave Technique (CWT used on smaller samples) and a Pulse Transmission Technique (used on larger samples).

Single-trip multi-zone (STMZ) Frac-Pack completions can significantly reduce the time to complete wells with long productive intervals. This technique was used successfully in two Lower Tertiary completions in the deepwater Gulf of Mexico (GOM) Cascade/Chinook project in 2010 (26,000 ft TVD, 8900 ft water depth). With interval lengths exceeding 1,000 ft, reservoir pressures greater than 18,500 psi, and bottomhole temperatures higher than 250°F, these STMZ completions were the first of their kind. With a STMZ completion, all completion intervals in a well are perforated at once. Then all the lower completion hardware (screens, sleeves, packers, etc.) is assembled and run in the well and the packers are set. Through the manipulation of sliding sleeves, each interval is individually opened and frac-packed sequentially from the bottom interval to the top. Before moving to the next interval, the sleeves are closed and pressure tested, providing isolation between the wellbore and the reservoir. The steps are repeated until all the intervals are stimulated. The STMZ system saves a great deal of rig time over conventional stacked frac-pack systems by significantly reducing the number of trips in and out of the well with the work string. This paper discusses the challenges, planning, execution, and results of these STMZ completions with a focus on the downhole completion hardware. Also discussed are some planned modifications to the system that will reduce risk and improve performance in the future.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe key objective of hydraulic fracturing in tight formation gas reservoirs is the creation of "effective" fracture length. The creation of effective fracture length requires that sufficient fracture conductivity be developed to allow effective fracture fluid cleanup. It is also fairly well understood that occasionally conventional cross-linked gel fracture stimulations do not create the desired fracture dimensions. The potential reasons for the shorter than desired effective fracture lengths are numerous with the most likely being excessive fracture height growth and poor fracture fluid cleanup. In the context of the Cotton Valley Formation bounding beds necessary to contain a large hydraulic fracture are non-existent except for the Taylor sand. Studies have been conducted of fracture fluid clean-up which indicate that fluid clean-up or more importantly the lack of fluid clean-up is a primary cause of ineffective or less than desired fracture length. This ineffective clean-up is believed to result from (1) the effects of time and temperature on proppant 1 , (2) gel residue and its damage to the proppant pack 2 , (3) viscous fingering through the proppant pack 3 , (4) the effects of unbroken gel on proppant pack permeability 4 , (5) non-Darcy and multi-phase fluid flow effects 5-7 , and (6) capillary pressure 8 . More recent studies 9-15 have shown that for effective cleanup of fracturing fluid and length, a Dimensionless Fracture Capacity, F CD , in excess of 10 is required to overcome yield power-law effects. Dimensionless conductivities of this magnitude are not being generated with many cross-linked gel fracs.Elimination of polymer by fracture stimulating with treated water is cheaper and may provide more effective fractures. However, the use of treated water, results in poorer proppant transport due to the low fluid viscosity. Though more of the created fracture would be effective (no polymer damage) less fracture will likely be created (poor transport). Performance comparisons of Cotton Valley wells fracture stimulated with water and cross-linked gel indicate that water fracs in addition to being cheaper also perform similarly or nearly so to crosslinked gel fracs (and in some cases better).This paper details the application of treated water fracs to the East Texas Cotton Valley Formation and documents an evaluation of well performance and the cause and effects of hydraulic fracturing with treated water on productivity. Through developing an understanding of this well performance behavior, guidelines and/or success criteria are developed for the design and execution of successful water fracs in the Cotton Valley Formation or any tight formation gas reservoir. These guidelines consider all aspects of the fracturing process including reservoir, geomechanical, and design considerations for successful application of treated water as a fracturing fluid. These guidelines, in conjunction with an in depth review of the Cotton Valley Formation, were utilized to dev...

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.

The Cascade and Chinook fields 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 anaverage 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. Thefracs 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 ofthe 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 thisprocess 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.