Vera, Vanessa (Halliburton) | Torres, Carlos A. (Halliburton) | Delgado, Eduardo (Halliburton) | Pacheco, Carlos (Halliburton) | Higuera, Josue (Equion Energia Limited) | Torres, Monica (Equion Energia Limited)
To measure and analyze reservoir pressure, conductivity, gas/oil ratio (GOR), and skin value, it is necessary to run a pressure buildup (PBU) test to the corresponding zone of interest in the well. This paper describes how the implementation of a coiled tubing (CT) real-time fiber-optic (RTFO) integrated system and a retrievable packer were determining factors to successfully develop both PBU in an upper formation and a pressure evaluation in the lower formation in the same run.
To help ensure isolation and evaluation of each high potential zone in the well, conventional methods involve multiple procedures requiring multiple runs. Using the CT RTFO (
This new technology helped the operator overcome challenges and deliver improved service quality. Real-time data acquisition during the packer setting helps ensure correct inflation, and continuous monitoring of the isolated zone during the PBU process helps ensure data accuracy and defines the end of data acquisition time once radial flow has been observed in the pressure transient analysis; therefore, the points previously discussed strongly impact production by optimizing operation time. Avoiding the use of materials such as cement to isolate the mentioned zones made this operation environmentally friendly. The greatest value of this technology is that it makes real-time monitoring of both the upper and lower zones possible at the same time.
The PBU test was successfully developed by determining reservoir pressure, skin, and flow regime of the near zone formation with precision and confidence, which helps the operator make decisions about future stimulations. High-pressure stimulation was achieved, which resulted in 460 BOPD over the initial production. Finally, a downhole ball-drop tool was effectively used to help ensure that packer setup was accurate and to reduce intervention time.
This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique.
A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water.
Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
Almeyda, Oscar (Equion Energia Limited) | Castañeda, Claudio (Equion Energia Limited) | Higuera, Josue (Equion Energia Limited) | Torres, Monica (Equion Energia Limited) | Portela, Fernando (Equion Energia Limited)
A Coiled Tubing Gas Lift (CTGL) pilot project was implemented in a reservoir with a compositional fluid system in the Casanare foothills area in the northeast of Colombia. This paper presents the life cycle of the project from design to operation including production test results after installation to "revive" wells with high water production and very low gas liquid ratio. High pressure gas was injected through conventional 1-3/4" and 2" 110 Kpsi coiled tubing, installed inside completion strings and hung to the Christmas tree to reduce cost of the project and avoiding recompletion of the well in a low-cost environment. A pilot project included three well was executed ending 2015, being a world first CTGL for 1-3/4" and 2" CT deployment beyond 12,000 feet. Challenges for deployment of CT string, well control aspects, barriers for control upon disabling of DHSV and master hydraulic valve among of moderate CO2 corrosion impact were some of the risks associated to this project. A pilot installation on three wells was successful and this paper compiles lessons learnt from this process including candidate selection, deployment, material selection, well intervention and risk assessment among of operational performance and pipe recovery after end of project life.
Vera, Vanessa (Halliburton) | Torres, Carlos A. (Halliburton) | Delgado, Eduardo (Halliburton) | Pacheco, Carlos (Halliburton) | Sampayo, David (Halliburton) | Higuera, Josue (Equion Energia Limited) | Torres, Monica (Equion Energia Limited)
Underbalanced perforating with conventional cable operations involves several risks associated with well tortuosity, cable tension capacity, gun lifting, and the capability of achieving the optimum underbalance for effective tunnel cleanup (
CT-conveyed perforating is ideal for this type of wellbore. To achieve the proper underbalance and depth correlation to perforate the target interval, an RTFO CT system provides the most accurate and reliable depth correlation process, in addition to real-time pressure and temperature monitoring inside the CT and the outer annulus.
Using the RTFO CT system, only two runs were necessary to complete the perforating program, in accordance with the operator design, rather than performing an additional run needed for pickling and to generate underbalanced conditions.
The use of the RTFO CT system can help to prevent correlation errors resulting from CT elongation.
A CT structure was not necessary to deploy the guns based on the finite model analysis that calculates maximum stress and flange bending, including a safety factor.
A hydraulic firing head can be used with an RTFO CT system to activate the guns without affecting the integrity of the fiber optics or the downhole sensor tool after detonation.
The RTFO CT system enabled the operator to evaluate the reservoir potential. The evaluation results indicated that one of the zones is a low producer, which avoided the pumping of unnecessary nitrogen to induce the specific zone.
The use of a downhole pressure sensor enabled the identification of the time at which the guns were detonated.
Improvement to the rigup was evidenced and enabled time optimization without affecting the operation.
The casing collar locator (CCL), used for depth correlation, was a crucial factor in reducing operational costs because it helped to optimize placement accuracy and gun detonation and to prevent misfiring (
A successful perforating operation was completed with 4,000 psi underbalance in a new formation using hydraulic detonation with continuous real-time downhole condition monitoring before and after detonation, enabling the operating company to make decisions in real time.
This new approach of using an RTFO CT system combined with the hydraulic firing head can be used to perforate new formations in these crucial scenarios (wells with production greater than 20 MMscf/D and zones with continued sand production).
The objective of Sembrando Joropo is to create a Traditional Music School that will develop the artistic potentials of children and adolescents in the areas of influence of Equión Energía through training in music and dance in order to form a seedbed of instrumentalists, musicians, singers and dancers for the cultural future of Casanare, which will provide spaces for healthy coexistence and the construction of social fabric. The program is carried out in schools, together with formal education, with the guidance and support of instructors, instruments, uniforms and a syllabus structured in six semesters. Children freely choose to learn how to sing, dance or play instruments of the Llanero tradition: the harp; the accompanying cuatro; the joyful maracas; and the Llanero mandolin. Values such as devotion, discipline and perseverance are shared, and group work is carried out through the creation of groups, ensembles, choirs or dance groups, which plays a role in building tolerance, appreciation for the work of others and respect for their contributions. This is aimed at seeking excellence as a commitment of everyone involved.
Javier, Urdaneta (Halliburton) | Mauricio, Tarache (Halliburton) | Carlos, Gonzalez (Halliburton) | Luis, Quiroga (Halliburton) | Ramirez, Zoraya (Equion Energia Limited) | Silva, Paula (Equion Energia Limited) | Ingrith, Villamizar (Equion Energia Limited) | Oscar, Zuleta (Equion Energia Limited)
Market dynamics are forcing petroleum operators to undergo complex drilling operations in remote locations in search of new sources of oil. This change in approach has meant that new technologies play an important role in the planning and development of such projects.
Because of deeper well drilling construction, running casing has become a challenging operation. The use of rigs with high torque and drag capacity, pipes with premium connections, and chemical lubricants in the mud make drilling projects significantly more expensive. The complexity of well construction has led to running casing and effective zonal isolation being major challenges, wherein operational practices limit the ability of powerful rig equipment, and thus the length of each section. For this reason, reducing the friction factor has become a key to building high inclinations and extended reach wells.
Rigid-resin centralizers based on carbon fiber ceramic composites have been applied successfully for highly tortuous wells. The use of friction reducers can improve the efficiency of running casing and help secure its settlement to the desired depth, helping reduce time, lowering costs, and minimizing problems. Running centralization in different casings and liners can have the effect of raising the string off the low side of the well, reducing contact area (drag) and improving cleaning efficiency during circulation. This results in less time washing and reaming during runs through interbedded formations.
This paper presents the advantages of using friction reducers chemically bonded to the casing to help reduce torque and drag and maximize casing standoff for primary cementing operations. The knowledge, lessons learned, and field procedures described can be applied to help address zonal isolation problems in vertical, deviated, and horizontal wells with high dogleg severity, helping reduce both operational time and associated costs.
Rossen, William Richard (Delft University of Technology) | Ocampo-Florez, Alonso Alonso (Equion Energia Limited) | Restrepo, Alejandro (Equion Energia Limited) | Cifuentes, Harold D (Equion Energia Limited) | Marin, J. (EquiÃ³n EnergÃa Ltd)
The ability of foam to divert gas flow over a long period of gas injection in a Surfactant Alternating Gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery. Here we interpret field data from the foam test in the Cusiana field in Colombia, South America (Ocampo et al., 2013). In this test surfactant was injected into a single layer that had been taking about half the injected gas before the test; then gas injection resumed into all layers. Based on the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended about 5.3 m from the injection well: fortunately the results to follow are not sensitive to this estimate. Based on the change in injection logs before the test and at day 5 of the test, when approximately 30 pore volumes of gas has been injected, foam still reduced gas mobility in the treated layer by about a factor of 9. We base this estimate on the decrease of injection into the treated layer and the increase into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1250 pore volumes gas injected), foam reduced gas mobility in the treated zone by about a factor of 4 and 2, respectively.
This result suggests that foam continued to reduce mobility by a modest amount even after long injection of gas. In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. In a design where a larger bank of surfactant were injected, a much greater and longer diversion of gas would be expected. On the other hand, foam did weaken progressively as it dried out. Foam models where foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.
Enhanced oil recovery by gas injection (CO2, hydrocarbon gas, N2 or steam) can be efficient in displacing oil where gas sweeps, but suffers from poor sweep efficiency because of geological heterogeneity, gravity segregation, and viscous instability between injected gas and resident fluids (Lake, 1989). Foam is a promising means to improve sweep efficiency in these processes (Schramm, 1995; Rossen, 1996). Field-trial data on foam effectiveness are relatively few (Hoefner et al., 1995; Patzek, 1996; Zhdanov et al., 1996; Turta and Singhal, 1998; Skauge et al., 2002). We report here on a field test of foam for diversion to correct for reservoir heterogeneity, and in particular on the long-time diversion achieved by a limited surfactant slug in this test.