Fracture Calibration Tests (FCT), are strategically used to estimate, amongst other important parameters, reservoir permeability and pore pressure during early appraisal stages of unconventional formations, where estimation of permeability and pore pressure by pressure transient buildup tests is impossible because no flow occurs without hydraulic fracture stimulation. This study investigates some of the idiosyncrasies that have been reported in a large number of FCTs, which make after-closure (AC) analysis ambiguous or inconsistent.
We recently introduced a novel comprehensive model for FCT analysis, combining before-closure (BC) and AC behavior in a fully consistent way, facilitating the detection of abnormal BC events (i.e. multiple closure and non-linear leakoff) and improving the intrinsic weakness of standalone AC analysis methods. Extensive use of this model on a vast number of shale gas FCTs has revealed the existence of apparent AC anomalies. This paper provides a novel approach to identify and diagnose these apparent anomalies and reconcile them with unique aspects of the tested unconventional shale formations.
In the AC anomaly that we firstly addressed in SPE-144028-MS, the logarithmic derivative shows only a minimal indication of formation linear flow, showing instead an abrupt transition to pseudo-radial flow. This unresolved anomaly inspired the work presented in this paper, where twenty FCT published case histories were used to study and reveal four distinct anomalies: AC logarithmic derivative exhibits unit slope, a symptom of horizontal fracture; Multiple closures followed by AC logarithmic derivative that exhibits a late-time "hook"; AC logarithmic derivative exhibits abrupt transition to pseudo-radial flow with limited or no linear flow; AC logarithmic derivative exhibits an apparent dual porosity "dip".
AC logarithmic derivative exhibits unit slope, a symptom of horizontal fracture;
Multiple closures followed by AC logarithmic derivative that exhibits a late-time "hook";
AC logarithmic derivative exhibits abrupt transition to pseudo-radial flow with limited or no linear flow;
AC logarithmic derivative exhibits an apparent dual porosity "dip".
These AC idiosyncrasies have been rationalized and integrated into our established comprehensive model for FCT analysis, allowing a realistic characterization of the geological, tectonic, and wellbore -related geometric signatures that very commonly manifest themselves in all shale formations.
Ghasemi, M. (Petrostreamz) | Astutik, W. (Petrostreamz) | Alavian, S. (Pera A/S) | Whitson, C. H. (Pera A/S) | Sigalas, L. (Geological Survey of Denmark and Greenland) | Olsen, D. (Geological Survey of Denmark and Greenland) | Suicmez, V. S. (Maersk Oil and Gas A/S)
The purpose of this study is to present the numerical and experimental evaluation of the tertiary-CO2 flooding (CF) at high operating pressure and reservoir temperature. In this study, water flooding is followed by CO2 injection into an outcrop chalk core with a centralized fracture. Our validated numerical models reproduce the result of core flooding experiments. In addition, we upscale the simulation model and investigate the scale dependency of the diffusion mechanism in a larger matrix-fracture domain.
The experiments used an outcrop core which is vertically placed in the core-holder with the total length of 28 cm and the diameter of 12.3 cm. The axial "fracture" is represented by a centralized hole with the diameter of 2.2 cm. We utilize the Wood's Metal technique to initially saturate the chalk core with the North-Sea-Chalk-Field (NSCF) live oil. The core sample is aged to restore the chalk wettability at the operating conditions. Then, the water flooding (WF) is performed by injecting brine from the bottom of the fracture and producing the oil from the top. After no additional produced oil is observed, the WF is stopped. A "shut-in" period follows, which allows preparing the rig for tertiary-CO2 flooding. CO2 is then injected from the top and the hydrocarbon streams are produced from the bottom of the fracture. The whole core flooding is operated at constant reservoir conditions at 300 bara (4351 psia) and 110 ºC, which is higher than the typical NSCF reservoir conditions (258 bara and 110 ºC). This allows us to investigate the efficiency of the tertiary-CF at a higher operating pressure condition.
We employ a compositional reservoir simulation with a developed equation of state (EOS) to model the experiment. An automated history matching procedure is developed to match the experimental results. The modeling workflow is capable of taking into account the significant vaporization effect observed during CF when the rich-CO2 enters the three-phase separator. An upscaling study is conducted to evaluate the performance of CF in a single and multiple fracture-matrix systems. Moreover, the accuracy of dual porosity models is tested against the reference single porosity model.
We accurately model the WF experiment through tuning the oil-water capillary pressure and relative permeability data. The numerical model is capable of reproducing the CF lab results by employing the best match multi-component diffusion coefficients. Moreover, we successfully model the excessive water production during CO2 injection by taking into account the hysteresis effect in water-oil capillary pressure and relative permeability.
Comparing these results with our previous work at lower reservoir pressure shows the positive effect of pressure on increasing the efficiency of the tertiary-CF in recovering more oil from a matrix-fracture system. Also, the tuned capillary pressure and relative permeability during WF indicate an active imbibition drive and a strongly water-wet system.
In the upscaling work, we consider the effect of several key parameters on oil recovery; e.g. matrix block size, fracture spacing, CO2 injection rate, gravity drainage, vaporization and the diffusion. The results show that the mass transport is mainly dominated by diffusion in the lab scale even though this is not the case in the large matrix block size.
Our findings are an important step towards modeling the tertiary-CO2 flooding in an actual fracture-chalk system. We also provide some important inputs that are necessary for upscaling tertiary-CF from a lab-scale into a field-scale reservoir model.
The growing acceptance of Distributed Temperature Sensing (DTS) has been contributed by its accurate real-time estimation of the staged fracturing effectiveness. The objective of this study is to develop a new model to simulate fluid flow and temperature profiling of horizontal wellbores with complex fracture geometries. This study offers an enhanced estimation of key reservoir and fracture properties with DTS, which may throw light on the further optimization of the fracturing projects. Specifically, we developed a comprehensive numerical model to simulate flow and temperature field in unconventional reservoir with DTS. In our robust wellbore model, multiphase flow with slippage is simulated accurately. Flow and thermal models are fully coupled between wellbore and reservoir model. The new model was validated with exiting simulator of OLGA and CMG. After validation, we applied our model to simulate single fracture and five fractures cases with varying parameters. The impacts of several parameters, including reservoir matrix permeability, fracture conductivity, reservoir rock thermal conductivity, heat exchange coefficient, fracture spacing, and fracture geometry, on temperature profile along the wellbore were analyzed. Several practical conclusions have been drawn from the sensitivity analysis. Although numerous simulators have been developed to simulate the DTS data, relatively few existing models can handle the multiphase flow with slippage, heterogenous reservoir properties and fracture with complex geometries due to the complexity of the calculations and computational cost. Our model is more rigorous than the prior models to simulate the DTS data through the advanced wellbore and reservoir models.
The decommissioning of wells and restoration of natural subsurface barriers which prevent hydrocarbon flow to surface, is a critical activity in well life which removes environmental impact for the future after oil/gas production facilities have been removed. Despite reduced rig/equipment costs, abandonment continues to be a substantial expenditure and represents a significant liability for operators in a cash constrained environment. While we see many efforts to reduce scope of abandonment and workover operations, engineered design and execution must comply with regulations as defined in the Code of Federal Regulations (CFR) without compromising safety.
Abandonment and workover activities in the deepwater Direct Vertical Access (DVA) environment are typically conducted with a platform installed rig. However, there exists a significant amount of work involved in rig workover activities (cement plug installation, tubing cutting, circulation to workover fluid, etc) which do not require the physical workover unit itself and therefore can be accomplished "offline" both to save rig days, cost, personnel exposure, etc. In this context, "offline" will be defined as the time associated with activities that may be accomplished without dedicating critical path rig time to abandonment scope, reducing time and cost, assuming this identified rig would not otherwise be idle. Saved time may be used to provide value in a number of capacities from drilling and completing new wells to working over or abandoning another well.
This paper discusses the case histories of two wells accessible via a deepwater Tension Leg Platform (TLP) in the Gulf of Mexico (GoM), both of which were scoped for conventional producer zonal abandonment and recompletion/workover activities. One would be worked over to another target production zone ~7000’ up-hole while the other would be worked over and converted into a new field injector for a major water flood project in the region. Through meticulous pre-planning, engineering design, and contingency development, the engineering and operations teams working on these two wells were able to reduce the critical path time of the work unit by realizing offline opportunities.
These activities utilized conventional intervention techniques of slickline, electric line, and available pumping to both abandon these wells in an unconventional manner and ready the wells for immediate tubing pull once the rig was skidded atop. This was all done with full compliance with the CFR, in a "through-tubing" method, and satisfied abandonment conditions and operational safety requirements of the operator. While both wells noted significant savings either to acceleration of operation timeline or of first oil, the work conducted required decisive challenge management to succeed. The engineering decisions made, scope reductions identified, and trouble time events incurred will be discussed to the detail possible in this manuscript.
It has often been said that "Technical skills get you hired, and soft skills get you promoted." Whether they are called "soft skills," "nontechnical skills," or "professional skills," the incorporation of soft skills into the development of technical professionals is evolving and becoming more critical to both employers and technical professionals. Because of the "Big Crew Change," new supervisors and technical leaders will take on new responsibilities, which will require them to rely upon their soft skills. Ensuring that soft skills training is embedded with technical training prepares future leaders.
The quality of the technical contribution increases when individuals work more collaboratively. Soft skills help to improve personal effectiveness, providing a vehicle with which to deliver business results. Soft skills enhance expected business outcomes of the technical professional's work product. A variety of methods are utilized in professional development to disseminate best practices in soft skills to technical professionals. In addition to SPE, several other professional and technical societies are placing an increasing emphasis on soft skills development.
There are several ways to measure the impact, both qualitatively and quantitatively, of incorporating soft skills into professional development for engineers. One way of measuring the impact includes surveying participants and their supervisors according to Kirkpatrick's levels of evaluation. It is challenging to incorporate soft skills development into existing rigorous engineering degree curricula or corporate onboarding programs without sacrificing the emphasis on development of technical competency.
Increasingly, it is becoming more apparent that the value of the effort to incorporate soft skills, pays off in multiple ways to both the corporation in achieving their strategic objectives and to the working professional in realizing their career development goals. Common themes from case studies, surveys and benchmarking with other professional technical societies will illustrate how to deliver better business outcomes with soft skills.
Chevron has addressed the challenge of providing global learning opportunities for the early career development employees in a cost constrained, budget restricted environment. One solution was to pilot the blended learning versions of Petroskills' Production Operations 1 and Applied Reservoir Engineering. This presentation is a case study of sessions that were completed in 2016 and 2017.
Using industry approved content from two production and reservoir engineering courses, blended skill modules were developed to cover all key aspects of the traditional instructor-led course. Each module uses the most effective mode of delivery, including videos, narrated slideshows, interactive exercises, reading assignments, and live virtual instructor led sessions. Based on competency models, knowledge is transferred and assured with pre-assessment and post assessment testing. Learners advance at a pace that suits their work situation and learning style. The blended method delivers content that is relevant to current job roles, just-in-time.
The primary benefits of blended learning observed from the two pilot sessions are 1) reduced expenses, travel, and days away from work, 2) increased flexibility in learning styles and schedule preferences, 3) optimized learner's use of time and knowledge with test-out option, 4) metrics to prove learning occurs via pre and post assessments, 5) allowed for networking and communication among learners, 6) longer time to digest the material and retain knowledge according to adult learning principles. Key learnings are to engage internal stakeholders early and often, emphasize the message that this type of learning requires learners to take ownership of the course schedule, and leverage internal metrics (i.e. scorecards) to not only keep learners on track but to also improve quality of skill modules. Change management is a key component to a successful blended delivery.
This approach to blended learning is a relatively new concept for both oil and gas operators and learning and development organizations. The methodology and lessons learned presented in this presentation will benefit others who are evaluating the feasibility of incorporating blended learning into their organizations.
Mohammadzadeh, Omid (Schlumberger-Doll Research Center) | Taylor, Shawn David (Schlumberger-Doll Research Center) | Eskin, Dmitry (Schlumberger-Doll Research Center) | Ratulowski, John (Schlumberger-Doll Research Center)
One of the complex processes of permeability impairment in porous media, especially in the near wellbore region, is asphaltene-induced formation damage. During production, asphaltene particles precipitate out of the bulk fluid phase due to pressure drop, which may result in permeability reduction due to both deposition of asphaltene nanoparticles on porous medium surfaces and clogging of pore throats by larger asphaltene agglomerates. Experimental data will be used for identification of parameters of an impairment model being developed. As part of a larger effort to identify key mechanisms of asphaltene deposition in porous media and develop an asphaltene impairment model, this paper focuses on a systematic experimental study of asphaltene-related permeability damage due to live oil depressurization along the length of a flow system.
An experiment was performed using a custom-designed 60-ft slimtube coil assembly packed with silica sands to a permeability of 55 mD. The custom design included a number of pressure gauges at regular intervals along the coil length which enabled real-time measurement of the fluid pressure profile across the full length of the slimtube coil. Test was performed on a well-characterized recombined live oil from the Gulf of Mexico that is a known problematic asphaltenic oil. After saturating the slimtube coil with stock tank oil (STO) to restore wettability and attain the initial state of the test, the STO was then gradually displaced by flooding at least 3 pore volumes of live oil above the asphaltene onset precipitation (AOP) pressure. The impairment portion of the experiment was then initiated by maintaining initial pressure at the inlet while the outlet pressure was regulated slightly above the saturation pressure. Under this constant differential pressure, the injection flow rate through the slimtube decreased over time as the porous medium became impaired. During the impairment stage, samples of the produced oil were collected on a regular basis for asphaltene content measurement. After more than a month, the impairment test was terminated, and the live oil was purged from the slimtube coil with helium at a pressure above AOP pressure, and then the whole system was gently depressurized to bring the coil to atmospheric conditions while preserving the asphaltene damaged zones of the coil. Changes in permeability and porosity of the porous medium were obtained due to asphaltene impairment caused by pressure depletion.
Results indicated that the coil permeability was impaired by about 32% due to pressure depletion below AOP pressure, with most of the damage occurring in the latter section of the tube which operated entirely below the AOP pressure. Post analytical studies indicated lower asphaltene content of the produced oil samples compared to the injecting fluid. Asphaltene deposition distribution along the length of the coil was determined by cutting the slimtube coil into 2 to 3 ft long sections and using solvent extraction to collect the asphaltenes in each section. The extraction results confirmed that the observed permeability impairment was indeed due to asphaltene deposition in the middle and latter sections of the coil, where the pressure was below the AOP pressure.
Foam diversion has industry recognition as a proven approach to diversion in remedial sandstone acidizing in deep-water environments. With long intervals and large displacement volumes it is critical that a stable diverter reach the perforations with sufficient viscosity to sustain diversion effectiveness. Industry publications and laboratory testing indicate that non-stabilized foam systems tend to breakdown over time. A novel sandstone acidizing diverter (SSAD) system was recently developed and applied successfully in the field.
The new SSAD system is comprised of a surfactant based gelling agent prepared in an ammonium chloride base fluid. The formulation of the SSAD system can be altered as needed to obtain desired rheology and break profile. In order to demonstrate the viscosity potential of this system, formulations without breaker were prepared in the laboratory for each specific well application at bottom-hole temperature. For instance, a formulation designed for 240 °F bottom-hole temperature, provided a stable viscosity slug of 300 cp at 100s-1 for six hour duration. The system maintained viscosity above 100 cp at 40s-1 after six hours with internal breaker.
In 2015, two wells in deep water Gulf of Mexico with 200°F bottom-hole temperatures and an average perforated interval of 114 ft were treated with an organic mud acid treatment with no diverter. These zones were then re-stimulated in late 2016 with the same organic mud acid system and the new SSAD system. The initial production of the two wells treated in 2015 versus the re-stimulation treatment in 2016 showed a twofold production increase. Diversion pressure response was observed to be as high as 285 psi.
The SSAD system can be applied in wells with low and elevated bottomhole temperatures up to 300°F. The SSAD system is non-damaging to the formation and will break in presence of hydrocarbons, or an internal breaker can be added for enhanced clean-up. Other features include extended fluid stability and no additional mixing equipment or personnel requirements compared to foam.
The case study of the two wells in deep water Gulf of Mexico demonstrates the effectiveness of the new SSAD treatment compared to the conventional treatments without diversion being previously pumped in the Gulf of Mexico. Not only do SSAD treatments provide enhanced diversion compared to foam, on average, the cost of an SSAD system is 25% less than a treatment using foam diversion.
Chen, Li (Schlumberger) | Forsythe, Jerimiah C. (Schlumberger) | Wilkinson, Tim (TALOS Energy) | Winkelman, Ben (TALOS Energy) | Meyer, John (Deep Gulf Energy) | Canas, Jesus A. (Schlumberger) | Xu, Weixin (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Shan, Dan (Schlumberger) | Hayden, Ron S. (Schlumberger) | Gendur, Jason (Schlumberger) | Hearn, Richard (Schlumberger) | Kumar, Anish (Schlumberger) | Lake, Patrick (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Reservoir architecture and the size and reservoir quality of producing bodies remain a central concern particularly in deepwater. In this case study, high-quality seismic imaging delineated the sand bodies and an intervening shale break between two stacked sands. Wireline evaluation in each well consisted of advanced DFA (Downhole Fluid Analysis), formation sampling and pressure measurements, borehole imaging and petrophysics. Reservoir fluid geodynamic analysis of Wireline asphaltene gradient measurements indicate that each sand body is laterally connected and that the shale break could be a baffle. Geodynamic analysis of reservoir architecture employing seismic analysis and wellbore imaging and petrophysical logging concludes the same. All other PVT and geochemical data are compatible with this assessment; nevertheless, the DFA-measured asphaltene gradients are shown to be superior to all other fluid measurements to determine reservoir architecture. The concurrence of high-resolution seismic imaging with advanced wireline for both formation and reservoir fluid geodynamics enables building robust geologic models populated with the accurate fluid structures of the reservoir. History matching months of production match most probable reservoir realizations which are now the basis of reservoir simulation. Future exploration with step-out wells are being optimized with this powerful workflow.
Zhang, Qiong (Baker Hughes Incorporated) | Chace, David (Baker Hughes Incorporated) | Inanc, Feyzi (Baker Hughes Incorporated) | Wu, Jianghui (Baker Hughes Incorporated) | Yuan, Peng (Baker Hughes Incorporated) | Gade, Sandeep (Baker Hughes Incorporated)
One important application of a multi-detector pulsed neutron instrument is to detect gas response for obtaining quantitative gas saturation in the formation. Obtaining this saturation value is achieved by differentiating the gas response from the liquid response. The maximum formation sensitivity to gas and liquid is observed when the wellbore is filled with liquid. When the wellbore is filled with gas, however, the separation between formation gas and liquid responses is reduced. This reduced separation results in increased uncertainty in the log analysis. The current operational solution is to set a plug and the fill the borehole with water or brine. Although this technique helps to obtain the desired formation gas-liquid sensitivity, it incurs increased operational expenses, excessive damage to the fragile formation, re-invasion effects, etc.
To overcome these challenges, a sleeve has been designed to deploy with the pulsed neutron instrument. The sleeve imitates the presence of water in the borehole around the tool and increases the dynamic range to the levels seen with the boreholes filled with water and oil-based fluids. This technique extends the application of multi-detector pulsed neutron instrument to provide solutions in air- or gas-filled boreholes. It avoids the potential damage to the formation, diminishes HS&E hazards, and reduces operational expenses by eliminating the operation of loading the borehole with water or brine.
The sleeved pulsed neutron instrument has been evaluated using Monte Carlo nuclear modelling for design and validation. Prior to any deployment, a sensitivity analysis is conducted using Monte Carlo N-particle transport code (MCNP) to evaluate the formation sensitivity improvement due to the presence of the sleeve. The impact of various tool-sleeve positions and the performance of various sleeve materials are also studied in this work. One application case-study is presented in this paper to demonstrate how the sleeved pulsed neutron tool significantly improves formation gas sensitivity as compared to the standard tool in gas-filled boreholes.