Bale A.,Statoil |
Smith M.B.,NSI Technologies |
Klein H.H.,HK Technologies
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2010
The success of conventional fracturing (using non-reactive fluids to carry proppant) and acid fracturing is dependant on both the creation of effective fracture conductivity and fracture penetration (fracture half-length). With acid fracturing, non-uniform acid-etching (or differential etching) of the fracture face creates lasting conductivity as long as stable points of support (asperities) exist along the etched fracture length. These hold the channels open and connected to the wellbore following fracture mechanical closure. However, both field experience and laboratory work have shown that even fairly competent carbonates soften and creep under closure stresses after contact with acid, thus, potentially resulting in poor retention of acid-etched fracture conductivity. Preservation of fracture conductivity becomes even more challenging in case of high effective closure pressure. Furthermore, acid fracture conductivity is dependant on surface etching patterns, which are determined by uneven permeability and mineralogy distributions. Therefore, a very clean, homogeneous isotropic carbonate may not be a good candidate for acid fracturing since a fairly uniformly etched fracture might close completely at bottomhole producing pressures. Also, carbonate formations with more than approximately 30 percent insoluble components are generally not good candidates because overall acid-etched fracture conductivity may be impaired due to low solubility and also the release of insoluble materials may tend to plug any conductive etched patterns created by the acid. The effective length of the acid-etched fracture is limited by the distance the acid can travel along the fracture and adequately etch the fracture faces before becoming spent. When acid fracturing, the etched length, not the hydraulic length, is considered the effective fracture length. Effective acid penetration will most often be shorter than any proppant placement (due to often high and increasing leak-off rates with time, and high reaction rates, especially at elevated temperatures). An indeed rare, but in theory, powerful well stimulation technique is the combination of acid fracturing (i.e., creation of a hydraulic fracture using reactive acid fluid) with proppant (CAPF) to provide permanent conductivity. Unless proppant is squeezed into the acid fracture before the end of the job, the conductivity of an acid fracture is vulnerably retained pending the stability of asperities all along the height/length of the fracture. Thus, the desire to include proppant in fracture acidizing treatments is conspicuous (but not limited to) "clean" carbonates (exhibiting uniform mineralogy and permeability), carbonates at high effective stress conditions, "soft" carbonates of any permeability (excluding high porosity chalks), low temperature dolomites (with low reaction rates) and together with organic acids where small and vulnerable etched-fracture widths are prevalent. Also, intuitively, effective fracture half-length may be extended if acid (or non-reactive fluids) can transport proppant beyond the etched penetration length "all the way" to the hydraulic tip of the fracture or even extend the hydraulic length for typical short acid fractures. A methodology proposed by Dowell more than three decades ago "Maximum Conductivity Stimulation" (MCS) is probably the first discussion of the idea of combining acid with proppant fracturing. However, the idea did not establish roots in the oil and gas industry for reasons discussed in this paper. Clearly, one missing ingredient was the lack of today's state of-the-art modeling tools for determining suitable applications and procedures. This paper presents and uses a recently developed planar 3D, gridded, FEM (finite element method) multi-layer (with varying percent of limestone/dolomite including non-reactive layers) acid fracturing model. This model fully couples rock mechanics (fracture width and propagation), matrix and natural fracture fluid loss (and effects of acid and non-acid gel fluid stages to increase and reduce fluid loss, respectively), acid reaction/acid diffusion, fluid flow, and proppant/acid transport into a single solution. Such a capability is unique at this time, and, in general, only a 3D gridded model is capable of such simulations due to the complex interactions. Case histories are examined in this paper as possible targets for CAPF. The extraordinary simulation results from modeling of this combined process and its impact on well productivity are discussed. Copyright 2010, Society of Petroleum Engineers.
Haddad Z.,FOI Technologies |
Smith M.,NSI Technologies |
De Moraes F.D.,Petrobras |
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 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. Copyright 2011, Society of Petroleum Engineers.
Haddad Z.,FOI Technologies |
Smith M.,NSI Technologies |
De Moraes F.D.,Petrobras
SPE Drilling and Completion | Year: 2012
The Cascade and Chinook Project is located in the Walker Ridge area in the Gulf of Mexico (GOM), 250 miles south of New Orleans in depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth subsea (TVDss), with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises 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 Moraes et 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 multizone (STMZ) sand-control system. Some of these design challenges are briefly discussed by Cunha et al. (2009). Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operational standpoint because of a continuous, multistage frac operation. Some of the operational limitations included service-tool erosion limitations because of 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 fracturestimulation program for the Lower Tertiary formation in the Cascade and Chinook Project. 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 highdensity 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 (caused by 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 envir onments. Copyright © 2012 Society of Petroleum Engineers.
Deng J.,NSI Technologies |
Hill A.D.,Texas A&M University |
Zhu D.,Texas A&M University
SPE Production and Operations | Year: 2011
The conductivity of acid-etched fractures depends on spaces along the fracture created by uneven etching of the fracture walls remaining open after fracture closure. In this study, we have modeled the deformation of the irregular fracture surfaces created by acid etching and the resulting fracture conductivity as closure stress is applied to the fracture. In our previous work, we modeled the dissolution of the fracture surfaces in a formation having small-scale heterogeneities in both permeability and mineralogy. This model yielded the geometry of the etched fracture at zero closure stress. Beginning with this profile of fracture width, we have modeled the deformation of the fracture surfaces as closure stress is applied to the fracture. At any cross section along the fracture, we approximate the fracture shape as being a series of elliptical openings. Assuming elastic behavior of the rock, we calculate how many elliptical gaps remain open and their sizes as a function of the applied stress. The sections of the fracture that are closed are assigned a conductivity because of small-scale roughness features using a correlation obtained from laboratory measurements of acid-fracture conductivity as a function of closure stress. The overall conductivity of the fracture is then obtained by numerically modeling the flow through this heterogeneous system. Our previous work shows that high fracture conductivity can be created in acid fracturing if heterogeneity of the rock leads to the formationof channels along the fracture surfaces. In this study, we have determined how the channels in acid fracturing remain open as closure stress is applied. This model predicts the rock characteristics that are necessary for acid-fracture conductivity to be sustainable under high closure stress. © 2011 Society of Petroleum Engineers.
Snyder D.,Packers Plus Energy Services |
Anderson M.,NSI Technologies |
Ibara A.,HighMount Exploration and Production |
Elizondo O.,HighMount Exploration and Production
Society of Petroleum Engineers - Unconventional Resources Technology Conference, URTeC 2015 | Year: 2015
An operator working on the outskirts of the Ozona Arch sub-play of the Wolfcamp Shale successfully installed a 38-stage openhole multi-stage (OHMS) completion system with a cemented-back long string under a very short lead time. Additionally, the stimulation treatment was unique in the area due to high proppant concentration and aggressive proppant ramp. An overview of the equipment utilized, design process, drilling methodology, completion system, hydraulic fracturing and mill out operations will be presented. The Permian Basin, one of the top five resource plays in the United States, is the nation's most prolific oil-producing area. Crude oil production in the basin has increased from a low-point of 850,000 bbl/d in 2007 to 1.35 million bbl/d in 2013. The increase in Permian crude oil production is mainly concentrated in six low-permeability formations: Spraberry, Wolfcamp, Bone Spring, Glorieta, Yeso, and Delaware (Budzik and Perrin, 2014). The focus of this paper is on the Wolfcamp Shale, which is made up of several different layers of organic rich shales, intermingled with sandstone and siltstone. Capital investment in horizontal drilling operations targeting the Wolfcamp Shale is expected to exceed $12 billion during 2014 and surpass the amount invested in the booming Bakken shale of North Dakota by 2017 (Paul, 2014). With so much at stake in the Permian Basin, operators have experimented with various completion methods the past several years to more economically develop their acreage. An OHMS completion system with a cemented-back monobore well design will be highlighted in this paper as a viable solution for operators drilling and completing horizontal wells in the Permian Basin. The following discussion includes steps taken by the operator to successfully design, install and hydraulically frac a 38-stage system under a short lead time. These steps enabled the operator to achieve significant cost savings compared to its previous wells in the area and achieve initial production rates that exceeded the Wolfcamp type curve. Copyright 2015, Unconventional Resources Technology Conference.
Montgomery C.T.,NSI Technologies |
Smith M.B.,NSI Technologies
JPT, Journal of Petroleum Technology | Year: 2010
An extended overview of the history of the fracturing technology is presented. Fracturing can be traced to the 1860s, when liquid nitroglycerin (NG) was used to stimulate shallow, hard rock wells in Pennsylvania, New York, Kentucky, and West Virginia. In the 1930s, the idea of injecting a nonexplosive fluid (acid) into the ground to stimulate a well began to be tried. But when Floyd Farris of Stanolind Oil and Gas Corporation (Amoco) performed an in-depth study to establish a relationship between observed well performance and treatment pressures that formation breakdown during acidizing, water injection, and squeeze cementing became better understood. The first fracturing treatment used screened river sand as a proppant. Conventional cement- and acid-pumping equipment was used initially to execute fracturing treatments. Development of equipment including intensifiers, slinger, and special manifolds continues for hydraulic fracturing.