The primary objective of hydraulic fracturing is to create a propped fracture with sufficient conductivity and length to optimize well performance. In permeable reservoirs, the design objective is to achieve a Dimensionless Fracture Capacity, CfD, of at least 2. In lower permeability applications, additional conductivity is required (CfD > 10) to allow effective fracture fluid cleanup and optimized well performance. In some tight formation gas applications, conventional cross-linked gel fracture stimulations are not creating the desired fracture dimensions. The potential reasons for the shorter than desired effective fracture lengths are numerous with the most likely being reservoir heterogeneity, excessive fracture height growth, and poor fracture fluid cleanup. In recent years, there has been much discussion regarding the causes for, or reasons that the dimensions of the hydraulic fracture are shorter than desired. These include: relative permeability effects, fracture fluid cleanup, multi-phase flow, and non-Darcy flow. The former causes and reasons have been investigated in some detail; however, little data has been published regarding the effects of non-Darcy flow on fracture conductivity and effective fracture length. Some in the industry have suggested that tight gas well performance is hindered significantly by non-Darcy flow effects. This view, though potentially correct, is supported by little actual data in the literature. Further, to mitigate this effect, tip screen-out fracturing techniques and larger fracture stimulation designs often utilizing much more expensive ceramic proppants have been recommended and executed even in very low permeability applications. These methods may not be effective in tight gas applications but they surely are more expensive, potentially eroding the economic benefits of fracturing these low deliverability applications. In addition, little actual well performance data has been presented to justify the importance of non-Darcy flow in fractures with much of the justification coming from the use of semi-analytical calculations and spreadsheets. This paper will document an investigation of non-Darcy flow to hydraulically fractured oil and gas well performance. The investigation will utilize both a three dimensional single-phase numeric finite difference simulator and actual well performance to investigate the importance of non-Darcy flow to hydraulically fractured oil and gas wells. This paper will demonstrate the following:The importance or lack of importance of non-Darcy flow on hydraulically fractured oil and gas well performance,Compare and contrast actual well performance of off-setting wells where sand and ceramics were utilized in East Texas, Trinidad, and North Sea applications,Develop treatment guidelines and fracture design objectives to limit/mitigate the effects of non-Darcy flow across a broad spectrum of fracturing applications. Introduction The industry has been aware of the potential for non-Darcy flow in propped fracture for many years - since the pioneering work by Cooke.1 Since that work, much additional technology has been added, and that history has been well covered and will not be reviewed here (except as appropriate below). The primary problem was that the importance of this behavior was, at best, difficult to prove or quantify. The "problem" was that fracturing was traditionally (at least in the 70's and 80's when this idea was broached) applied to low permeability formations. The traditional, "definitive" test for non-Darcy effects (multi-rate drawdown) was difficult to apply operationally to such wells, and, again, at best, difficult to interpret as normal fractured well transient flow tends to mask non-Darcy effects. More recently, several papers have dealt with new analysis approaches that may make analysis for these effects more definitive in the future, but that is outside the realm of this work. Because of this "problem", the bulk of the literature has dealt with theoretical (analytical and numerical and semi-numerical) studies and extensive laboratory testing. However, very few papers have examined well test data over a range of conditions to compare the magnitude of the non-Darcy effects with these predictions.
Procedures, photographs, diagrams, results and recommendations are shared from an operation to remove sand plugs from a high pressure deepwater well with a failed lower completion. Specific recommendations minimize risk and provide for the safe handling of sand on the surface as the oil passes below bubble point pressure and undergoes rapid expansion. This paper includes photos, diagrams and lessons learned from an operation conducted during the month of December 2011.Removing sand plugs from a live well entails multiple risks. As the hydrocarbon is circulated to surface gas will evolve and expand rapidly, increase the velocity of the mixture and pose the risk of loss of containment due to erosion, especially if sand is entrained within the mixture. Any interruption to surface handling of wellbore fluids and sand creates the risk of stuck coiled tubing. Coiled tubing stuck inside production tubing in a live well would result in an unwelcome and probably difficult fishing job. Literature ReviewA number of papers on coiled tubing cleanouts are provided in the attached references. However none of the papers specifically address the safe handling of sand on surface. SPE 166531 Risks and Mitigations.Risks and mitigations are outlined below. RiskMitigations Flammable Hydrocarbon Gas Equipment layout allowed all liquid flowing out of the well to be contained in pressurized tanks with venting to the production platform vapor recovery unit or flare. Hydrocarbon ContaminationAll liquids were contained in pressurized tanks. The well was maintained hydrostatically overbalanced by use of the coiled tubing choke to keep the well from flowing. Sticking the Coiled TubingMultiple flow paths and redundant equipment minimized the chance of shut-in. The rate of penetration of sand plugs was synchronized with purging of the sand buster.Provisions were made to inject additional liquid (drill water) upstream of anticipated plugging points such as the sand busters. Erosion of Surface Equipment.The well was never allowed to flow, so the maximum rate was dictated by the circulation rate of the coiled tubing. Much of the sand was removed upstream of the bubble point. Multiple vessels allowed for multiple pressure steps. We had multiple spare chokes as well as a complete spare choke manifold (on a standby boat). Damage of CT Pumps by Solids 800 barrels of brine (4 times tubing volume) were on hand to allow us to dispose of used liquids. Extra tanks were provided for settlement of solids for recycle of brine. Planning.The same contractor, Schlumberger, operated the coiled tubing unit and the flow-back equipment. This helped ensure close communication during planning and execution. Bronco provided sand buster equipment and personnel. Emphasis was placed on the need for close communication and coordination. Extra supervisors were hired to ensure the operation went smoothly and folks had adequate rest. Schlumberger modeled flow in the surface equipment to ensure rates would stay below erosive velocities at the planned circulation rates. All con...
Historically, hydraulic fracturing has been principally applied to low permeability formations as a means of stimulating a well's production performance. In recent years, hydraulic fracturing for formation control as well as enhanced productivity in high permeability unconsolidated formations (i.e., frac-packing) has gained broader acceptance. This paper reviews frac-pack results in the Mahogany Field, a large gas-condensate field producing from unconsolidated high permeability sands. Even though frac-packing was very successful in these applications, numerous other completion techniques such as high rate water packs and conventional gravel packing are available and still being utilized throughout the world. For a field development engineer, few guidelines are available which aid in optimizing completion decisions. Field examples from Mahogany Field in offshore Trinidad are used to demonstrate a successful completion design selection procedure. The benefits and risks of gravel packs, high rate water packs, and frac-packing in the completion of high deliverability wells in these unconsolidated formations will be reviewed. Results of rock mechanics, fines migration, and embedment testing will be presented and coupled with a production optimization study to develop completion guidelines applied in Mahogany Field. Finally, this paper will show a direct comparison of a gravel pack completion (80 mmcfpd) and a frac-pack completion (160 mmcfpd) in offset wells from the same productive horizon. Current production performance and long term recovery predictions will be reviewed. This paper will make the following technical contributions:Present the results of an extensive laboratory study of rock mechanics, fines migration, and embedment testing, and show the value of such testing in making completion decisions.Develop and present guidelines for determining the optimal completion practices in high permeability unconsolidated formations.Show a direct comparison between a conventional cased-hole gravel pack completion and a frac-pack completion.Present details of a successful frac-pack completion in a formation with severe fines production problems. Introduction Historically, gravel packing was the principal means of formation control in unconsolidated formations. Efficient gravel pack formation control must take into account a number of formation and reservoir characteristics, gravel size, and well performance objectives. Numerous authors1–3 ave suggested gravel sizing criteria ranging from 4 to 10 times the 10 percent coarse point on a cumulative sieve analysis for formation control. The use of these criteria resulted in numerous gravel pack failures especially in U.S. gulf coast sands. As a result of the failures, additional investigations were conducted and new criteria were developed, with the most widely accepted criteria for gravel sizing proposed by Saucier4. This criteria recommends a gravel size six times the mean particle size in unconsolidated reservoirs. This sizing criteria has been utilized for many years to control formations, however, some production impairment due to fines migration and pack plugging has been noted. In recent years, studies have shown the importance of sorting5 on formation control and that larger gravels6–8 can effectively control some formations without production impairment. These studies, however, were limited to specific formations and did not consider the effects of stress on fines generation, migration, and gravel pack plugging. They also did not consider the implications of frac-packing on gravel size criteria and formation control.
Deepwater production well design and equipment installation present multiple challenges. One major problem is the uncontrolled heat transfer to outer annuli which can be detrimental to the integrity of the well. Annular pressure buildup (APB) could result in casing failure and heat loss from the production tubing causes dramatic loss of well productivity due to the deposition of paraffin and asphaltenes and could contribute to the formation of gas hydrates. Vacuum insulated tubing (VIT) was initially utilized in the deepwater well completions to help alleviate well failure caused by APB. The operator requested an alternative to VIT that would provide the following benefits: Reduced costs Minimization of APB or similar to VIT Increased flow assurance Ability to apply the downhole tools required to be installed in the production string Ease of placement was also an issue. Typically VIT takes special handling equipment, long lead times, and adds 10-12 hours of rig time for running of the production tubing. Customized high performance aqueous-based insulating packer fluid (IPF) proved to be a reliable alternative to VIT. A properly designed fluid having a density of 10.0 lb/gal and thermal conductivity (k) of 0.176 BTU/h ft°F was carefully prepared. The unique thermal-gelling characteristics of this state of the art fluid allowed for easy, rapid placement of the fluid in the well annulus. Once in the wellbore, the fluid has provided increased flow assurance as well as a reduction in APB thus resulting in increased well flow rates and improved profitability. Repeated field applications of this tailored aqueous IPF helped in achieving an overall cost reduction of more than 64% compared to utilizing conventional VIT. This paper presents detailed fluid formulations with laboratory data generated by specialized equipment, and discusses the fluid design criteria along with the reported data and economics.
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