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Introduction The three primary functions of a drilling fluid--the transport of cuttings out of the wellbore, prevention of fluid influx, and the maintenance of wellbore stability--depend on the flow of drilling fluids and the pressures associated with that flow. For example, if the wellbore pressure exceeds the fracture pressure, fluids will be lost to the formation. If the wellbore pressure falls below the pore pressure, fluids will flow into the wellbore, perhaps causing a blowout. It is clear that accurate wellbore pressure prediction is necessary. To properly engineer a drilling fluid system, it is necessary to be able to predict pressures and flows of fluids in the wellbore. The purpose of this chapter is to describe in detail the calculations necessary to predict the flow performance of various drilling fluids for the variety of operations used in drilling and completing a well. Overview Drilling fluids range from relatively incompressible fluids, such as water and brines, to ...
GlassPoint Solar was founded in 2008 to replace the use of natural gas for steamflooding heavy-oil reservoirs. But amid low energy prices, its chief investor has decided to pull the plug for good. The projects are designed to reduce technical risks in enhanced oil recovery and expand application of EOR methods in conventional and unconventional reservoirs. There is every reason to believe that enhanced oil recovery through huff-and-puff injections in US tight-oil plays could be a technical success across large numbers of wells. However, widespread economic success remains uncertain.
This paper presents an analysis of a CO2-foam-injection pilot in the Salt Creek Field, Natrona County, Wyoming. A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Aqueous foam has been demonstrated to have promise in conformance-control applications. This paper explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A growing chorus of suppliers, researchers, and service companies is persuading US operators to re-examine their use of slickwater in shale plays and consider displacing it with carbon dioxide and nitrogen.
In overbalanced drillng (OBD), a mud weight is selected that provides a hydrostatic pressure of 200 to 1,000 psi above the reservoir pressure. In UBD, we select a fluid that provides a hydrostatic pressure of around 200 psi below the initial reservoir pressure. This provides a good starting point for the selection of a fluid system. During the feasibility study, this drawdown is normally further refined, depending on the expected reservoir inflow and other drilling parameters. This first look provides an indication if the fluid should be foam or gasified or if the well is drilling with a single-phase fluid (Figure 1).
Inlet device in an oil/gas separator is used to direct the flow and absorb the flow momentum of coming stream. However, the inlet has received less attention and "science" than the gas outlets. Actually inlet device play an important role in overall performance of a separation vessel. Figure 1--Thaditional inlets that are commonly used but might negatively affect separation: (a) impact plate, (b) dished head, (c) half-open pipe, and (d) open pipe at vessel head (courtesy of CDS Separation Technologies Inc.). These inlets, although inexpensive, may have the shortcoming of negatively affecting separation performance.
An oil/gas separator is a pressure vessel used for separating a well stream into gaseous and liquid components. They are installed either in an onshore processing station or on an offshore platform. Based on the vessel configurations, the oil/gas separators can be divided into horizontal, vertical, or spherical separators. In teams of fluids to be separated, the oil/gas separators can be grouped into gas/liquid two-phase separator or oil/gas/water three-phase separator. Based on separation function, the oil/gas separators can also classified into primary phase separator, test separator, high-pressure separator, low-pressure separator, deliquilizer, degasser, etc. To meet process requirements, the oil/gas separators are normally designed in stages, in which the first stage separator is used for priliminary phase separation, while the second and third stage separator are applied for further treatment of each individual phase (gas, oil and water). Depending on a specific application, oil/gas separators are also called deliquilizer or degasser.
Steam-foam has been used extensively in field trials to improve steam conformance, both for cyclic steam injection and steam flood. It is a proven process and very useful lessons can be drawn from these field trials to plan new projects. However, foam has not yet been used to improve SAGD (Steam-Assisted Gravity Drainage) performances. The aim of this paper is to examine the reasons for this situation and discuss the practical aspects of Foam-Assisted SAGD (FA-SAGD).
After a thorough description of the main mechanisms involved in these processes (steam-foam for cyclic steam injection and steam flood, as well as foam for SAGD), this paper proposes to review the differences between the various processes and their implications for the design and implementation of FA-SAGD. Finally, based on the lessons drawn from all the documented steam-foam trials, potential and drawbacks of FA-SAGD are presented together with suggested roadmaps to address these remaining and newly identified challenges to make this technology come true.
By definition, the driving mechanism of SAGD relies on gravity and involves the use of a pair of horizontal wells drilled a few meters apart, one on top of the other. This is completely different from foam applications with both cyclic steam injection and steam flood, which are typically conducted with vertical wells; in addition, cyclic steam relies on single wells only whereas steam flood is essentially a lateral displacement process. Steam quality, injection velocity, proximity of the injection and production wells and the risks associated with the formation of emulsions in the surface facilities are some of the issues that are typically not problematic for foam with conventional steam processes, but which need to be considered before FA-SAGD can be implemented in the field. This work concludes that FA-SAGD is feasible but that ignoring any of these aspects would very likely cause the process to fail in the field.
This study will provide useful physical considerations on the steam-foam process along with detailed guidelines for the implementation of the Foam-Assisted SAGD process in the field. It will be useful for engineers that are considering foam to improve the performances of SAGD by targeting a reduction of the steam consumption or the Steam Oil Ratio.
Ocampo, Alonso (Gastim Technologies S.A.S.) | Restrepo, Alejandro (Gastim Technologies S.A.S.) | Clavijo, Julian (EQUION ENERGIA LTD.) | Cifuentes, Harold (EQUION ENERGIA LTD.) | Mejia, Juan Manuel (Universidad Nacional de Colombia-Sede Medellín)
This paper presents the development and successful implementation of the Foams technology as an effective EOR mechanism to improve the sweep efficiency of the gas injection in the Piedemonte fields. It also shows the process of optimization of the technology to adapt it to the Piedemonte operating conditions, which is based on massive hydrocarbon gas reinjection, and how this process led us to be at a state of the art position in this technology.
The methodology to adapt and further develop the foam EOR technology in Piedemonte was based on the Capital Value Process (CVP). It starts with a screening exercise, passes through a technical assurance including applicability, fluids compatibility, modeling and coreflooding tests at reservoir conditions. Finally, the specific solution is implemented in the field to confirm effectiveness. Initially the foams were deployed using the conventional Surfactant Alternating Gas (SAG) technique, but then the technology was optimized to better suit the operating conditions of the fields, and the last interventions have been done dispersing the foamer chemical in the gas stream.
This technology has been implemented in most of the fields in the Piedemonte and has proved success since the early implementation pilots in 2011. Implementation started in the Cusiana field, which is a matrix dominated system, and then moved to the naturally fractured and low porosity reservoirs located in the Recetor and Floreña fields. In all the cases, the implementation of foams has rendered positive results reflected in incremental oil production and flattening of the Gas Oil Ratio (GOR) at the influenced producer wells. The new developed dispersed Foams technology has been as effective as the conventional SAG in the jobs performed so far, with the advantages of requiring less surface equipment, and water consumption than SAG jobs. Benefits from Foams implementations so far add up to about 0.65 MM STB.
Main conclusions from this project are i) The foams EOR technology is fully applicable in the Piedemonte fields to improve the gas sweep efficiency and increase final oil recovery. ii) A new foam deployment technique based on the injection of the foamer chemical dispersed in the gas stream was developed, and proved effectiveness at the field.
The work is innovative in two ways: i) Effectiveness of foam as a technology to improve gas sweep efficiency in naturally fractured dominated systems was proved. ii) A new foam deployment technique based on the injection of the foamer chemical dispersed in a non-condensable gas stream was developed. Also this new foam EOR technique can be extrapolated to any other field operated under gas injection.
Perez, Romel (Ecopetrol S.A.) | Rodriguez, Hector (Ecopetrol S.A.) | Barbosa, Carolina (Universidad Industrial de Santander) | Manrique, Eduardo (Ecopetrol S.A.) | Garcia, Luis (Universidad Industrial de Santander) | Rendon, Gabriel (Ecopetrol S.A.)
Cyclic Steam Stimulation (CSS), is the most applied thermal enhanced oil recovery (EOR) method worldwide. However, despite the vast experience gained over the last few decades CSS still has its challenges including but not limited to energy efficiency and operational costs. CSS has been evaluated for several years in Colombian heavy oil reservoirs. As CCS approaches its maturity, new alternatives and injection strategies are required to potentially extend the technical-economic limit of this recovery process.
This work is focused on the procedure implemented during the design, execution and monitoring of the hybrid technology of steam plus foam as a strategy to improve the performance of a mature CSS process. The strategy developed for experimental tests, numerical simulations and pilot test is described. The evaluation of well head configuration, injection facilities and schedules to assure a good quality and stability of the preformed foam is also discussed.
The CSS-foam injection pilot was performed in Teca - Cocorna field. The cumulative surfactant injection was between 3 to 5 tons distributed between two mature wells under CSS at a concentration of approximately 2500 ppm. The facilities used for the foam generation with nitrogen at surface conditions and well injectivity performance will be discussed.
Early incremental production due to foam injection has been positive. The first CSS-foam pilot tests allowed the assimilation of lessons learned to incorporate best practices for the continuous improvement in the operation of CSS processes. The performance of CSS-Foam will be updated based on the pilot results due to the level of uncertainties associated with the scaling of laboratory results. According to the performance of the pilot, Ecopetrol will continue evaluating this hybrid CSS technology to improve oil recovery and energy efficiency in fields with steam injection.
The use of foams and energized fluids for hydraulic fracturing treatments has emerged as an interesting technology to increase oil and gas recovery in tight formations. However, there is limited understanding of the compositional and phase behavior of theses complex fluids during stimulation treatments. The present work provides a high-fidelity modeling platform that can capture the multiphase behavior of energized fracturing fluids and can be used to evaluate treatment designs.
The fluid flow is modeled using a multiphase multicomponent compositional model with a Peng-Robinson equation of state (PR-EOS). The fracture propagation is modeled using the phase field method. The framework allows the seamless ability to switch from stimulation to production scenarios. Numerical tests are conducted to study the effects of different injection fluids on the geometry of newly generated fractures.
Hydraulic fracturing is a widely used technology to extract oil and gas from tight and unconventional reservoirs. The process includes injecting highly pressurized fluids into the geologic formation to fracture the reservoir rocks.
Slickwater is the most commonly used fluid for this stimulation process. In addition to water, it contains friction reducers, along with other additives and surfactants to lower the viscosity and enhance the fracture network. Low viscosity fluids generate fractures with greater length and lesser width creating more complex fractures in the reservoir .
The general availability of water and its low cost has made slickwater a popular choice for fracturing; however, aqueous-based frac fluids present several major shortcomings. Each stimulation job can take up to 5 million gallons of water, placing significant stress upon local water resources . The amount of water recovered during flow-back can be as low as 15% and is usually contaminated with chemical modifiers, gelling agents, and proppants . The common practice is to re-inject it into the geologic formation, yet, large volumes of water re-injection have been linked to induced seismicity and fault re-activation [2, 3].
Another drawback of using an aqueous-based fracturing fluid is that it causes significant damage to the formation. Water gets trapped in the rock pores due to the very low permeability of shale and the capillary effects between the injected water and reservoir fluids . This phenomenon, known as water phase trapping, blocks the backflow channels for hydrocarbons and significantly damages the region near the wellbore . Fracturing water also induces swelling in clays decreasing the overall permeability .
The limitations involved in water-based fracturing have motivated the search for non-aqueous injecting fluids [5, 6]. Many fracturing fluid alternatives have been designed and tested over the years to increase reservoir productivity, reduce water requirements, and minimize environmental impacts [7, 8]. Commonly used fluids include CO2 and N2 in their different forms: energized, foam, gas mist, or liquid .