Pore pressure and wellbore stability estimation in real-time has become a mandatory service in any situation where drilling hazards are expected and particularly in the cases of deep water, exploration, geologically complex and extended reach settings. The basic workflow assumes that under-compaction is the primary cause of abnormal pore pressure generation (
Advanced mud gas interpretation and cavings (pieces of rock not drilled by bit or reamers) analysis have become important tools in real time pore pressure and wellbore stability monitoring and are used to determine the approach to a structural deformity (faults/fractures) or the presence of elevated pressures at the crest of a permeable formation, either due to lateral transfer or gas buoyancy. Analysis of cavings shape, structure and mode of generation helps to determine the current borehole condition and whether the mud weight (MW) needs to be raised to control the problem, or just modifying the drilling parameters would suffice. The presence of connection gas peaks aids the pore pressure analyst to estimate the pore pressure across a permeable formation by associating its magnitude and its relationship to dynamic (equivalent circulating density - ECD) and static (equivalent static density - ESD) environments. The use of Managed Pressure Drilling (MPD) to maintain a constant backpressure across the annulus, negates this fluctuating static to dynamic environment and hence affects the use of mud gas behavior to determine if the prevailing MW column is sufficient to provide static overbalance, but workflows to address this issue have been defined over the years. Although, the industry is currently beginning to use these secondary indicators into their workflows, there is no standard that incorporates these sources into a single, cohesive workflow.
This paper presents an integrated approach to pore pressure prediction and managing drilling risk by incorporating multiple sources of information beyond classical log-based techniques. It demonstrates the value of advanced mud gas interpretation, drilling mechanics interpretation, cavings and drilling parameter analysis to optimize the pore pressure model in real-time and enhance the traditional techniques.
Rossen, William R. (Delft University of Technology) | Ocampo, Alonso (Equión Energía) | Restrepo, Alejandro (Equión Energía) | Cifuentes, Harold D. (Equión Energía) | Marin, Jefferson (Equión Energía)
The ability of foam to divert gas flow during 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 (EOR). Here, we interpret field data from the foam test in the Cusiana field in Colombia (Ocampo et al. 2013). In this test, surfactant was injected into a single layer that had been taking approximately half the injected gas before the test; then, gas injection resumed into all layers. On the basis of 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 approximately 5.3 m from the injection well; fortunately, the results to follow are not sensitive to this estimate. On the basis of the change in injection logs before the test and at Day 5 of the test, when approximately 30 pore volumes (PVs) of gas (relative to the volume of the treated zone) had been injected, foam still reduced gas mobility in the treated layer to approximately 11% of its pretrial value. We base this estimate on the decrease of injection into the treated layer and the increase of injection into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1,250 treatment PV of gas injected), foam reduced gas mobility in the treated zone to approximately 26 and 50% of its value before the test, respectively.
This result indicates that foam continued to reduce mobility by a modest amount even after long injection of gas. On the other hand, foam did weaken progressively as it dried out. Foam models in which foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.
In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. Mobility in the foam-treated region in this test, after passage of many treatment PVs of gas injection, mimics that very near the injection well in a process with a larger slug of surfactant.
Fekete, Paul (University of Calgary) | Bruno, Lopez A. (University of Calgary) | Dosunmu, Adewale (Shell Aret-Adams) | Odagme, Samuel (Shell Aret-Adams) | Sanusi, Adewale (University of Calgary) | Bowe, Ediri (Dalhousie University)
Real time analysis of data and geomechanics (understanding the rock properties and stresses) has continuously improved the stability of wellbores in the world. Some of the issues cost by this instability are the most common of these losses are: borehole enlargement, cavings, washouts, stuck pipes, deformation of the casing and amongst others. Numerous wellbore instability problems related to drilling through potentially natural fractured reservoirs/formations have been reported. Most of the this reported formations are been characterized by number of macro and micro scale bedding planes and/or networks of natural fractures which weakens the mechanical strength of the rock and the producibility of potential of the rock matrix. This term paper reviews instabilities issues in Naturally Fractured Reservoirs (NFR), natural fracture reservoir failure mechanism and highlights the effect of instabilities in NFR as well as proper well placement in the NFRs. This paper also looked at wellbore solution in permeable and impermeable formations, borehole failure analyses, drilling strategies to mitigate instabilities in naturally fractured reservoirs and other countermeasures dealing with wellbore instability. The review shows that well design, drilling fluid design, minimizing lateral vibrations of drill pipe and good drilling practices are critical in solving wellbore stabilities in naturally fractured reservoirs.
With operations reaching a performance plateau, an operator and service company embarked on an ambitious project called "Well of the Future" (WoF Project) to increase well delivery performance, utilizing current technology, knowledge and experience. The main goal was to reduce overall well construction and completion cost and time up to 30%. In the past, wells typically took up to 300 days and USD 65 million to drill. Twenty years of drilling performance history in the Colombian Foothills were analyzed, and global ‘best practices’ reviewed to determine what innovative and sustainable solutions can be applied to future wells in the hydrocarbon-rich foothill license area and beyond. Many of the identified cost/time issues related to borehole instability occurred in the Carbonera Formation, a series of intercalated formations that include argillaceous and sandy-silty coal beds. The classical approach to evaluating borehole stability was not effective, and was expanded using additional formation evaluation data, fluids properties and historical operational data to gain a better understanding of the problem. Parameters that affect the Equivalent Circulation Density (ECD) were also evaluated, including: mud density, mud rheology, Rate of Penetration (ROP), gas, mud flow, restrictions and contaminants. In addition, caving volume measurements from offset wells were included in the pre-well study. During the execution of the first well, the caving rate data was fed into the real-time data management/visualization system and plotted together with all other factors that affect the ECD, enabling a more coherent analysis. Percentage of Caving shape was also plotted during drilling and tripping operations, enabling a deeper understanding of wellbore instability that included: Fragility of rocks associated with micro-fractures, sensitivity to the amount of mechanical energy applied to the weakest formations while drilling or tripping, time dependency, attack angle with respect to shale bedding plane and well trajectory, coal bed displacement and sealing strategy. All the information combined with Logging While Drilling (LWD) data and on bottomhole Measured While Drilling (MWD) enabled not only the detection of the events, but the understanding of the root causes. Results indicated that the mud weight and sealing management aren't enough to solve the wellbore instability in the Carbonera Formation. The solution involves other factors such as correct casing seat, BHA designs, trips frequency, pills record, identifying the stronger intervals to circulate, caving monitoring as a borehole quality indicator, and the handling of drilling assembly. As a result of this workflow, a new record for the field was achieved: 216 days of drilling for the total well (65 days faster than the original plan), where real time wellbore stability monitoring contributed to reduce the days of drilling of one of the most difficult sections and establishing lessons learned for further drilling campaigns.
Ocampo-Florez, Alonso (Equion Energia Ltd.) | Restrepo, Alejandro (Equion Energia Ltd.) | Rendon, Natalia (Equion Energia Ltd.) | Coronado, Jorge (Equion EnergÃa Ltd.) | Correa, Juan Alejandro (Equion EnergÃa Ltd.) | Ramirez, Diego Alejandro (Equion Energia Ltd.) | Torres, Monica (Equion Energia Ltd.) | Sanabria, Rosa (Equion Energia Ltd.) | Lopera, Sergio Hernando (Universidad Nacional De Colombia)
Foams have proved to be efficient to block temporarily high conductivity layers, and improving gas injection conformance and sweep efficiency in predominantly matrix reservoir systems, at least at lab and field pilot tests; nevertheless, its successful use in naturally fractured reservoirs has not been fully demonstrated as of today. This paper presents the evaluation process and the successful results for two (2) foam EOR field pilots performed in the Cupiagua in Recetor field; a gas condensate system whose main reservoir is a low porosity (<6%) quartzarenite with matrix permeabilities in the range of 0.01 to 10 mD, and where the fracture corridors are confirmed to play an important role both in well productivity/injectivity, and in the inter-well connectivity and gas channelling between gas injectors and oil producers.
The reservoir has been developed under massive hydrocarbon gas re-injection, and the current recovery factors of condensate are between 35-40%. The foam treatments were deployed in two gas injectors located in different areas of the field, each one impacting two oil producers, and exhibiting different levels of gas recycling, with GOR ranging between 40,000 and 100,000 scf/STB.
Both operations were performed via bull-heading using the SAG method. The results for both jobs showed a temporary reduction in gas injectivity, with slow recovery to its base line within the next 3 months. Despite showing little changes in the injection profile at the gas injectors, the two producers affected by the first job showed a clear change in GOR trends, and a consistent ramp-up in oil production rates during a period of at least 7 months, reaching a maximum increase between 15 and 30 % over their base line productions. The second job was performed to confirm consistency and repeatability of technology, and evaluate duration cycle of blocking and benefit effects. Early surveillance indicates positive response both at the gas injector, and the oil producers. Results herein presented, confirm the viability for foams as an EOR method for this naturally fractured field, and open EOR opportunities for other fractured reservoirs located in the same basin and exploited under gas injection schemes.
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.
Scale deposition is a serious oilfield problem, when two incompatible waters interact chemically and precipitate minerals. Typical examples are seawater with a high concentration of sulfate ions and formation water with high concentrations of calcium, barium, and strontium ions. Mixing these waters may cause precipitation of calcium, barium, and/or strontium sulfate. The removal of the entire sulfate content from seawater might be a costly process and requires highly advanced techniques (nanofiltration). This study was conducted to investigate the damage caused by deposition of calcium sulfate precipitation and to describe the damage by use of the material-balance method, and then a new technique is proposed to prevent the damage caused by calcium sulfate scale. Coreflooding experiments were performed to assess the damage caused by calcium sulfate and a computed-tomography (CT)scan was used to locate the damage inside the core. Chelating agents, such as hydroxyl ethylene diamine triacetic acid (HEDTA), ethylene diamine tetra acetic acid (EDTA), and hydroxy ethyl imino diacetic acid (HEIDA), were used to prevent scale deposition in the Berea sandstone cores. The pressure drop across the core caused by scale precipitation will be predicted analytically. The results of the experimental data showed reduction of permeability by 20% from its initial value after seawater injection, caused by calcium sulfate precipitation. The results of the new analytical model showed that in approximately 1 month, the injection will stop or the injection pressure will exceed the fracture pressure of the formation. High-salinity-water injection caused severe formation damage, and the injectivity declined faster compared with the low-salinity-water injection. The material-balance calculations showed a good match between the experimental, field, and predicted data. The developed model of the pressure drop caused by calcium sulfate precipitation was used to predict the pressure drop across the core, and its result was in a good match with the experimental results. The new method was effective in preventing and removing sulfate precipitation.
The revolution of the multistage horizontal completions has made low-permeability laminated reservoirs a cost-effective business. The key to success relies on maximizing the surface area contacted, a process that requires the adequate stage isolation technique. From traditional “plug and perf” to efficient sliding sleeves, the application of a particular system is related to the number of fractures that can be propagated during a single treatment injection. This condition varies according to rock and reservoir properties, principal stresses, zonal isolation and stimulation design.
This study introduces a methodology to build predictive repeatable models that integrate reservoir characteristics (mineralogy, pore pressure, thickness) along with mechanical properties of the rock (unconfined compressive stress, anisotropy, minimum horizontal stress, etc) and fracture pressure diagnostics (pressure history match, near-wellbore pressure analysis) to predict the likelihood of propagating multiple fractures per stimulation stage. Examples of the application of this workflow to select the suitable completion mechanism are provided using multiple datasets from the Williston Basin. Additionally, a calibrated production model measures the impact of a specific isolation method on well productivity.
Finally, this paper concludes with a series of sensitivities to determine the influence of different reservoir and rock properties in fracture propagation and provides recommendations regarding data requirements to apply this methodology in a particular field.
SPE 168262 Successful Application of Fiber-Optic-Enabled Coiled Tubing and Inflatable Packer Used for Testing the Formation's Upper Zone Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition held in The Woodlands, Texas, USA, 25-26 March 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
Ocampo, A. (Equion Energia Ltd.) | Restrepo, A. (Equion Energia Ltd.) | Cifuentes, H. (Equion Energia Ltd.) | Hester, J. (Equion Energia Ltd.) | Orozco, N. (Equion Energia Ltd.) | Gil, C. (Equion Energia Ltd.) | Castro, E. (Equion Energia Ltd.) | Lopera, S. (U. Nacional de Colombia) | Gonzalez, C. (U. Nacional de Colombia)
A successful field trial of foams as gas injection conformance enhancer has been deployed in the Cusiana field in Colombia, South America. This work describes the Front End Loading (FEL) process done to get to the field trial, the field operation itself, and the results obtained so far.
The Foam treatment was deployed in the Mirador formation of the Cusiana field, a low porosity quartzarenite with a recovery factor over 50%.The reservoir fluid is a volatile oil developed under an extensive gas reinjection process. The foam treatment was engineered to improve both the gas injection conformance at the wellbore and also the gas sweep efficiency deep into the reservoir.
An extensive FEL including chemical product screening, foam stability at reservoir conditions, coreflood experiments, reservoir modelling, and a careful selection of well candidates was executed for this pilot. The treatment was done in a gas injector well in the northern part of the field, where high RF has already been obtained with high levels of gas recycling.
The operation was performed using the SAG method. The foaming surfactant was pumped selectively in front of the dominant injection layer and then the well was put back on injection. The results showed a clear and sustained change in GI conformance reducing the injectivity of the treated layer by 60%. Increase in oil rate along with decreases in GOR was also observed in the nearby oil producers two months after the treatment. Results herein presented confirm the viability of foams as an EOR method for the Cusiana field and at least two other fields located in the same basin and exploited under similar conditions.
The Cusiana field currently operated by Equion Energía Ltd is located in the foothills of the Eastern Mountain chain in Colombia - South America, and started production in 1994. It comprises three stacked reservoirs (Mirador, Barco and Guadalupe) and two compositional fluid systems both being volatile oils with a rich gas cap near critical conditions with pressures and temperatures over 5000 Psia and 250 F respectively (Lee et al, 1996). Initial fluids in place added up to about 1.5 bn STB of oil and over 3 tcf of gas with Mirador formation bearing about 60% of total fluids. Development strategies have included natural depletion, gas recycling, water injection and gas injection redistribution. Gas recycling and re-distribution have provided the best recoveries so far.