Loss of barrier assurance and primary containment occurrences whether downhole or at surface have impacted safe well operation and production funnel significantly. Complex well head design, inadequate cement behind casing, threat of shallow gas presence and multiple downhole tubulars leaks are some of the common perils in sustaining the production. Apart from frequent pressure monitoring, risk assessment and mitigation plans to tackle the issues head-on, a new fresh perspective is required to manage well integrity and diagnostic holistically. This paper will highlight application of geochemical method as the new eye to trace source of well integrity issues and emulates forensic engineering to investigate well barrier failures.
Crude and gas compositional analysis from C1 up till C36 carbon chain plays a key role in determining the possible scenarios of leak paths and type of fluid expelled from the wellbore. The best forensic analysis could be produced utilizing multiple samples which represent different stages of well life starting from open-hole exploration drilling, development, production and towards the well abandonment stage. Comparing samples composition at each stage with reference to the baseline while evaluating the existing or newly acquired cement bond and diagnostic logs will help to complete the lingering puzzle.
Results showed that the origin of the fluid samples expelled from the wellbore are successfully traced in a much more economical way with faster turn-around time compared to the conventional diagnostic method. It helps to point out the most likely well integrity elemental failure which has triggered immediate actions to revive the production. Plan to feed in the cash flow has been accelerated 6 months ahead through work-over activities and number of unhealthy well strings has been reduced by 12%. Production deferment is also reduced by half million ringgit equivalent value.
In a nutshell, the case studies provide an eye-opening insight towards predictive and quantitative well integrity solutions to support production. Forward looking the geochemical forensic method can be further tailored for strategic well diagnostic solutions as more data comes in. Time to action could be further reduced with the introduction of advanced on-site analysis technology to boost the restoration efforts.
Reservoir fluid properties play a crucial role in the upstream field development cycle. Petroleum engineers extensively utilize Pressure-Volume-Temperature (PVT) studies in applications such as calculations of pipelines’ pressure drop, and assessment of Enhanced Oil Recovery (EOR) strategies. These studies are generated from a series of lab experiments conducted on reservoir fluid samples in high pressure-high temperature (HPHT) lab environments, and commonly matched using Equation of State (EOS) software.
Feeding and characterizing the composition of a reservoir fluid in a PVT software play a central role towards understanding its behavior. These steps are heavily affected by the last carbon number measured and the lumping scheme used in the simulator. This paper investigates the application of splitting the plus fraction, and utilizing Saturates, Asphaltenes, Resins and Aromatics (SARA) analysis in enhancing viscosity prediction at atmospheric conditions.
In this study, three oil samples from fields with suspected flow assurance issues were selected. A fingerprint study was first conducted on all samples to ensure that they are representative of the original reservoir fluid, and free of any drilling fluid contaminants. The methodology used in this study is based on conducting compositional analysis and viscosity test on the selected samples. Furthermore, SARA analysis was conducted to enhance the characterization of reservoir fluid, and confirm asphaltene presence. Lastly, splitting technique and SARA-based lumping scheme were used to predict viscosity values at atmospheric pressure and were compared to experimental data.
The results of this work demonstrated the effectiveness of SARA-based lumping scheme on atmospheric viscosity prediction, which captured the plus fraction concentrated in the dead oil without compromising the computational time. Furthermore, the EOS software used studied the sensitivity of the simulation results to different compositions.
Quintero, Harvey (ChemTerra Innovation) | Abedini, Ali (Interface Fluidics Limited) | Mattucci, Mike (ChemTerra Innovation) | O’Neil, Bill (ChemTerra Innovation) | Wust, Raphael (AGAT Laboratories) | Hawkes, Robert (Trican Well Service LTD) | De Hass, Thomas (Interface Fluidics Limited) | Toor, Am (Interface Fluidics Limited)
For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (
A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.
This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (
Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.
This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
Zhu, Ziming (Colorado School of Mines) | Fang, Chao (Virginia Polytechnic Institute and State University) | Qiao, Rui (Virginia Polytechnic Institute and State University) | Yin, Xiaolong (Colorado School of Mines) | Ozkan, Erdal (Colorado School of Mines)
In nanoporous rocks, potential size/mobility exclusion and fluid-rock interactions in nano-sized pores and pore throats can turn the rock into a semi-permeable membrane, blocking or hindering the passage of certain molecules while allowing other molecules to pass freely. In this work, we conducted several experiments to investigate whether CO2 can mitigate the sieving effect on the hydrocarbon molecules flowing through Niobrara samples. Molecular dynamics simulations of adsorption equilibrium with and without CO2 were performed to help understand the trends observed in the experiments. The procedure of the experiments includes pumping of liquid binary hydrocarbon mixtures (C10 C17) of known compositions into Niobrara samples, collecting of the effluents from the samples, and analysis of the compositions of the effluents. A specialized experimental setup that uses an in-line filter as a mini-core holder was built for this investigation. Niobrara samples were cored and machined into 0.5-inch diameter and 0.7-inch length mini-cores. Hydrocarbon mixtures were injected into the mini-cores and effluents were collected periodically and analyzed using gas chromatography (GC). After observing the membrane behavior of the mini-cores, CO2 huff-n-puff was performed at 600 psi, a pressure much lower than the miscibility pressure. CO2 was injected from the production side to soak the sample for a period, then the flow of the mixture was resumed and effluents were analyzed using GC. Experimental results show that CO2 huff-n-puff in several experiments noticeably mitigated the sieving of heavier component (C17). The observed increase in the fraction of C17 in the produced fluid can be either temporary or lasting. In most experiments, temporary increases in flow rates were also observed. Molecular dynamics simulation results suggest that, for a calcite surface in equilibrium with a binary mixture of C10 and C17, more C17 molecules adsorb on the carbonate surface than the C10 molecules. Once CO2 molecules are added to the system, CO2 displaces C10 and C17 from calcite. The experimentally observed increase in the fraction of C17 thus can be attributed to the release of adsorbed C17. This study suggests that surface effects play a significant role in affecting flows and compositions of fluids in tight formations. In unconventional oil reservoirs, observed enhanced recovery from CO2 huff-n-puff could be partly attributed to surface effects in addition to the recognized gas-liquid interaction mechanisms.
Cronin, Michael (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University) | Emami-Meybodi, Hamid (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University) | Johns, Russell (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University)
We present a new semi-analytical compositional simulator specifically designed for hydrocarbon recovery (primary and cyclic solvent injection processes) in ultratight oil reservoirs based on diffusion-dominated transport within the matrix. The semi-analytical solution consists of a well-mixed tank model for the fractures coupled to diffusive transport within the matrix. Production of oil, gas, and water from the fractures is proportional to its phase saturation. The matrix allows for differing effective diffusion coefficients for each component. Because there are no grid blocks within the matrix the analytical solution is computationally less expensive than numerical simulation while capturing the steep, non-monotonic compositional changes occurring a short distance into the matrix owing to multiple injection cycles. The Peng-Robinson equation-of-state is used to calculate phase behavior within the analytical framework.
The solution is validated with several lab and field-scale cases. For primary recovery, the results show that the diffusion-based simulator correctly reproduces the pressure and oil recovery declines observed in the field. We show that the hydrocarbon recovery mechanism for solvent huff‘n’puff (HnP) is facilitated by greater density reduction and compositional changes (increased compositional gradients). Two solvents are considered in HnP calculations; carbon dioxide (CO2) and methane (CH4). Recovery of heavier components is enhanced with CO2 compared to CH4, but methane has overall greater oil recovery than carbon dioxide for the cases considered. Furthermore, the results demonstrate that multiple huff‘n’puff cycles constrained to surface injection are needed to enhance density and compositional gradients, and therefore oil recovery. While shorter soaks are better for short-term recovery (i.e. 3 to 5 years), longer soak periods maximize recovery over a longer timeframe (i.e. 10 to 15 years). This paper provides a novel way to model the optimum number of cycles and duration and when to start the HnP process after primary recovery for the limiting case of diffusion only transport where matrix permeabilities are very small (k < 200 nd).
Wang, Ningyu (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX 78712, USA) | Prodanovic, Maša (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX 78712, USA) | Daigle, Hugh (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX 78712, USA)
Precipitation and deposition of paraffin wax and hydrates is a major concern for hydrocarbon transport in pipelines, tiebacks, and other production tubing in cold environments. Traditionally, chemical, mechanical, and thermal methods are used to mitigate the deposition at the expense of production interruption, complex maintenance, costs, and environmental hazards.
This paper studies the potential of nanopaint-aided electromagnetic pigging. This process has potentially low production impact, simple maintenance, low energy cost, and no chemical expense or hazards. The electromagnetic pig contains an induction coil that emits an alternating magnetic field. The alternating magnetic field induces heat in the nanopaint coating (i.e. coating with embedded paramagnetic nanoparticles) on the pipeline's inner wall and in the pipeline wall itself. The heat then melts and peels off the wax and hydrates adhering to the pipeline, allowing the hydrocarbon to carry them away.
We analyze the heating effectiveness and efficiency of electromagnetic pigging. The heating effectiveness is measured by the maximum pigging speed that allows deposit removal. The heating efficiency is measured by the ratio of the heat received by the wax over the total emitted electromagnetic energy, which we define as the pig induction factor.
Based on our numerical model, we compare the pig induction factor for different coil designs, different hydrocarbon flow rates, and different pig traveling speeds. We find that slower pig speed generally improves the pigging performance, that shorter solenoids with larger radius have higher efficiency, and that the oil flow does not considerably affect the process. We re-evaluate the maximum pig speed defined by the static pig model and confirm that a solenoid with larger radius allows higher pig speed.
We investigate the potential of a novel, low-maintenance electromagnetic pigging method that poses minimal interruption to production. This investigation is a basis for a new technology that stems from initial experimental investigation done by our collaborators. We here provide parameters for pig design and pigging protocol optimization, and will put them in practice in our future lab experiments.
Nafikova, Svetlana (Schlumberger) | Bugrayev, Amanmmamet (Schlumberger) | Taoutaou, Salim (Schlumberger) | Baygeldiyev, Gaygysyz (Schlumberger) | Akhmetzianov, Ilshat (Schlumberger) | Gurbanov, Guvanch (Schlumberger) | Eliwa, Ihab (Dragon Oil)
A major operator on the Caspian Turkmen shelf has started to encounter sustained casing pressures (SCP) attributable to insufficient isolation across a hydrocarbon gas zone, due to downhole stresses and other contributing factors. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming the requirement for an alternative cement system that can withstand anticipated stresses and resolve this challenge. An innovative and cost-effective solution was applied and successfully solved the SCP challenge due to its unique self-healing properties.
If cracks or microannuli occur and hydrocarbons reach the cement, the system has the capability to repair itself, restoring integrity of the cement sheath without external intervention. The cement system is placed conventionally in the annulus across or above the hydrocarbon-bearing formation. It then acts as a pressure seal, expanding to accommodate downhole changes and healing if any hydrocarbon reaches it. This technology has been used in four wells in the field with excellent results.
Two wells were used to demonstrate the capabilities of the self-healing cement as a lead cement slurry, which created a cap over the pay zones. The self-healing cement was designed with low Young's modulus for optimum flexibility. To minimize the risk of set cement integrity failure due to microannuli or microdebonding from chemical shrinkage after setting, linear expansion up to 1.2% was incorporated into the design. After cementing, the wells were intentionally exposed to a sequence of high-pressure tests, which induced annular pressures in the wells. However, because of the self-repair capability of this cement, isolation and integrity were effectively restored in the two wells within 1 to 2 weeks without external intervention. As a result, the self-healing cement technology has become the standard for the field for all future wells, and the operator plans to extend the self-healing cement technology to other fields with similar challenges.
This paper clearly demonstrates successful casing pressure remediation without intervention by engineering a flexible, self-healing cement system. The design strategy, execution, evaluation, and results for two wells are discussed in detail and will help to guide future engineering and operations around the world.
A. H. Khan, M. Faisal (Pakistan Petroleum Limited) | Abid, M. Faraz (Pakistan Petroleum Limited) | Fareed, Abdul (Pakistan Petroleum Limited) | Javed, Zeeshan (Pakistan Petroleum Limited) | Khan, M Noman (Pakistan Petroleum Limited) | Hashmi, Shariq (Pakistan Petroleum Limited)
Technical evaluation and subsequently devising an appraisal and development strategy of a structural cum stratigraphic reservoir based on a discovery well only is always challenging. The reservoir under discussion was discovered as a structurally bounded trap and the appraisal wells were drilled on NW-SE direction along with the main bounding fault based on this understanding. However, presence of hydrocarbon below the spill point, anomalous sand thickness, lateral facies and reservoir quality variations observed in few of the wells indicated stratigraphic component in the field. Further complexity was added when the deepest tested gas was assigned on the structural map which showed extension of the hydrocarbon play outside the block boundary where the area was under different operating company that later drilled multiple wells near the block boundary. Therefore, it was critical to estimate correct initial gas in-place and percentage distribution of hydrocarbon across the lease boundaries.
Well location map for the studied field
Well location map for the studied field
The objective of this paper is to present workflow that integrates multiple dataset to understand the field's hydrocarbon filling mechanism. Detailed geophysical and Petrophysical work has been carried out, which includes building of sequence stratigraphic framework, preparation of seismic attribute maps, understanding of the depositional setting for all the individual sand units encountered in all the wells, rock quality assessment (core and log methods with integration of capillary pressure curves), free water level (FWL) assessment, permeability modelling using machine learning approach (NN), pore throat radius estimation to relate hydrocarbon filling mechanism and saturation-height function modelling to build consistent 1D water saturation model.
Comprehensive dataset has been acquired to evaluate the potential of the field that covers 3D seismic for the entire field, biostratigraphic analysis for seven (7) well, conventional logs in twelve (12) wells and advance measurements like Elemental Capture Spectroscopy and high-resolution resistivity images in five (5) wells. Core analysis data also acquired in five (5) different wells including routine core analysis, capillary pressure measurements using high pressure mercury injections, pore throat radius, relative permeability measurements (Centrifuge), formation resistivity factor measurements and sedimentological analysis (XRD & thin section) to overcome the challenges and defining the uncertainty associated with initial gas in-place.
Sequence based boundaries were defined to correlate individual sand bodies using the core data, image logs, elastic logs, seismic transacts and attribute maps for understanding the depositional setting. Lat-er these correlations were used to build a consistent petrophysical model including VCL estimation from Gamma/Neutron-Density/Sonic Density methods which was validated with ECS/XRD data. Porosity model was developed and validated from the core porosity followed by variable "m" estimation from the porosity/m relationship using the SCAL data. Later on, the consistent water saturation (Sw) models were built for all the studied wells. Permeability models were built using Neural Network (NN) where core-based permeability used for calibration and the model was tested qualitatively with the mobility and the well test permeability. For the validation of Sw from the logs, capillary pressure-based flow units were built using FZI/RQI, Winland & BVW (log) methods to define flow units defined through the core data. It was observed that the Winland R35 method-based pore throat radius had good correlation with the Sw log. FWL from MDT to estimate the height of the gas column, Skelt Harrison equation to capture the shape of the capillary pressure curve and Swi from the Centrifuge analysis were used to calibrate MICP end point which helped in building consistent Saturation-height functions. Results showed good to excellent match from the modeled Sw (Pc) vs Sw(log).
Purewal, Satinder (Imperial College) | Juárez Toquero, Fidel (National Hydrocarbons Commission of Mexico) | Simón Burgos, Eduardo (National Hydrocarbons Commission of Mexico) | Meneses-Scherrer, Eduardo J. (National Hydrocarbons Commission of Mexico) | Arellano Sánchez, Elaine A. (National Hydrocarbons Commission of Mexico)
A Pilot project was initiated to classify Oil and Gas projects in 19 Blocks in Mexico using the United Nations Framework Classification (UNFC) which has a unique 3-dimensional evaluation structure with three axes: Economics, Environment and Social viability (E axis), Project Feasibility (F axis) and Geological Knowledge (G axis). The main focus was to capture the environmental and social impact on project classification and resources categorization.
The Pilot project was coordinated by the National Hydrocarbons Commission (CNH) with integrated collaboration from the Energy Ministry (SENER), the Agency for Safety, Energy and Environment (ASEA), and the Petroleum Work Group of UNECE. SPE classification system (i.e. PRMS) has been mapped to UNFC. While PRMS covers oil and gas projects only, UNFC covers all resources e.g. oil and gas, minerals, renewables, nuclear, etc.
The E axis uniquely differentiates UNFC from PRMS by its granular capture of social and environmental issues. A systematic approach was adopted with focus on E and F axes for which a matrix and a decision tree (‘flow chart’) were created for an efficient classification of the hydrocarbon volumes. For the G axis, the volume ranges provided by the project operators were considered to be valid. In the selected 19 blocks, there were 75 projects identified. These were located offshore, onshore and included conventional and unconventional projects with varying degrees of environmental and social issues.
This is the first known exercise using UNFC for integrating social and environmental issues into oil and gas projects for hydrocarbon volumes classification and categorization anywhere globally. The outcome shows the differences between the PRMS and UNFC due to social and environmental conditions. Using UNFC for classification and categorization of all energy sources of a country, a potential tool can be created for making energy policy decisions. This may also assist in meeting Sustainable Development Goals- 2030 adopted by most countries including the UN and The World Bank.
Classification using UNFC assists in identifying the key social and environmental drivers which may be impediments to moving the oil and gas volumes categorizations higher up the value chain. Added granularity in the classifications incorporating environmental and social considerations will assist project financial investment decision making through comparative assessment of objectives and priorities of national, regional and local stakeholders. To the authors’ knowledge, this is a unique Pilot project with significant value-add outcomes which can be replicated in other countries.
Hydrodynamics and geothermics are important tools for understanding the complex distribution of reservoir fluids in the Montney Formation in Alberta and British Columbia, Canada. The Montney comprises a conventional system in the east and an unconventional, Deep Basin-style hydrocarbon system in the west, where an underpressured, oil-dominated fairway just west and downdip of the conventional system grades further downdip into overpressured liquids and gas fairways.
The first part of this study addresses how these systems can be mapped from a pressure and temperature perspective. The Montney hydrodynamics system is explained using pressure versus elevation graphs. Key contours are taken from pressure-depth ratio maps to define the general boundaries between systems, noting that these boundaries change with depth. Geothermal gradient mapping is used to identify areas of prominent high or low geothermal gradients, which can have a significant effect on the positioning of gas liquids fairways. Key current day isotherms are also identified to represent the current phase windows by relating present-day formation temperatures to Tmax data.
To evaluate how pressure and temperature affect liquids production within the Montney, liquids production trends need to be considered. The second half of the paper discusses how mapping gas composition, particularly C2+ Wet Gas Index (WGI), may serve as a good proxy for liquids yields.
While the authors appreciate the complexities of phase behavior and the various factors influencing liquids production, the objective of this paper is to link trends that can be observed in liquids production to trends in pressure, temperature and gas composition. Ultimately, this paper examines ways in which hydrodynamics and geothermics can be used to help predict spatial variations in observed liquids production. By analyzing the co-relationships of the pressure, temperature and WGI data, the Montney segregates into two distinct domains which we term the Northern (British Columbia) Play and the Southern (Alberta) Play. This analysis can be tied in with other data sets for a better understanding of the reservoir such as: isotope geochemistry to gain insights into hydrocarbon migration; Special Core Analysis (SCAL) data to gain insights into fluid mobility; vapour-liquid equilibrium data to examine hydrocarbon fractionation during production; and completions data to provide a more complete picture of reservoir deliverability.