Drilling horizontal and highly permeable sandstone acid-sensitive reservoirs with oil based drilling fluids are normally followed by filter cake and associated organic sludge removal treatments. The acid or cleaning recipes should be compatible with the formation minerals, especially when losses are encountered. The objectives of this paper were to conduct a comprehensive evaluation of HCl/formic acid recipe to dissolve oil-based filter cake, characterize and dissolve associated organic sludges, and assess compatibility with highly permeable acid-sensitive sandstone core plugs.
Filter press experiments were conducted to optimize the fluid recipe. Core flood testing was conducted on sandstone core plugs at 160°F. Compatibility with reservoir fluids were assessed using aging cells. TGA was used to identify organic/inorganic composition of sludge samples XRD and ESEM were used to characterize core plugs and sludge samples. ICP analysis was conducted to analyses effluent from coreflood experiments. GC and GC-MS analysis was conducted to identify and characterize sludge samples. Micro CT scan was used to assess the dissolution of rock minerals.
The removal efficiencies of the oil-based filter cake were between 85-100% by weight using HCl/Formic acid recipe. The characterization of the sludge samples revealed the presence of mainly diesel. The inorganic compounds (50% by weight) were mainly quartz with small amounts of calcite, dolomite, kaolinite, microcline, and pyrite. Maximum solubility of nearly 60 wt% was achieved. Core flooding tests of the acid recipe indicated reduction in permeability of core plug. The coreflood effluent analysis indicated dissolution of mainly Ca, Fe, and Mg with small amounts of Al, Si, and Sr with indication of Si-based precipitation. No major indication of precipitation occured. ESEM and EDS spot analysis of the core plug particles showed the sample was comprised Si, O, Fe, S as the main constituents with small amounts of Al. XRD analysis of the core plug after coreflood testing showed the presence of mainly Quartz and small amounts of Microcline, Pyrite, and Palygorskite. The CT scan of core plug before/after coreflooding indicated the acid dissolved rock minerals. There was no clear indication of core damage or solids plugging.
Proppant diagenesis has been introduced recently as a damaging mechanism to the fracture conductivity in shale formations. The mechanism was used to explain the low values of the field-measured fracture conductivity as well as the long-term decline of the lab-measured API conductivity data. Previous studies revealed the presence of a diagenetic overgrowth on the proppant surface and around the embedment crater after being exposed to high-temperature and/or high-stress conditions. The objective of this paper is to experimentally investigate the diagenesis of bauxite proppant in calcite rich Eagle Ford shale fractures.
The interaction between the proppant and the formation was studied by aging its mixture in a deionized water for prolonged period of time at elevated temperature of 325°F to accelerate the involved reactions. Aluminum-based bauxite proppant of 20/40 mesh-size was mixed with a crushed Eagle Ford shale sample of 50/100 mesh-size. The mixture was aged at 325°F and 300 psia for three weeks. The surfaces of the proppant and the formation were examined for mineral overgrowth and dissolution using scanning electron microscope (SEM) with energy dispersive X-ray spectroscopy (EDS). The supernatant fluid was analyzed for cations’ concentrations using inductively coupled plasma (ICP) and the sulfate ion concentration was measured using a spectrophotometer. The proppant and Eagle Ford formation were then aged separately at the same conditions to explain the sources of the leached ions and the observed overgrowth materials.
The results show the diagenetic activity that could result from the use of bauxite proppant in Eagle Ford shale fracturing. The ICP results indicated the potential dissolution of the proppant at high temperature. The observed overgrowth materials were identified as calcium sulfate, calcium zeolite, and iron-calcium zeolite. The calcium sulfate was found to be explicitly sourced from the Eagle Ford dissolution-precipitation mechanism. The SEM/EDS results indicated the presence of calcium zeolite after aging both cells: the proppant/formation mixture and the formation alone. The iron-calcium zeolite was found on the proppant surface as a result of the fluid/proppant/shale interactions.
The study contributes to the understanding of the damaging mechanisms to the fracture conductivity in the Eagle Ford shale formation. Results impact the choice of proppant and fluid for fracturing optimization and long-term production sustainability in the Eagle Ford shale reservoirs.
The petroleum industry needs persons with a wide variety of skills for its efficient operation. A catalogue of these skills is therefore very useful to any entity, be it country or company, entering the petroleum industry. This paper describes the human resource needs of the industry on the basis of the value chain of the industry.
The petroleum value chain starts with activities aimed at searching for and finding petroleum and ends with production and sales of crude oil and natural gas to refineries and end users. The technical needs for each section of the value chain are depicted by a model that describes the skills required from the technician to the professional level in addition to the specialist skills. These specialist skills are not always at the professional level. For each section of the value chain the technical skills are built around a particular discipline such as geoscience or petroleum engineering.
The final result is a three dimensional model with ‘technical complexity’ represented in one dimension, ‘value chain variation’ represented in the second dimension and the different entities in the industry represented by the third or ‘entity’ dimension. Along the ‘entity’ slice of the model e.g. for the regulator, the base skills of the disciplines for each section of the value chain are modified or tuned to the needs of a regulatory body such as the ministry of energy for all sections of the value chain. By way of example, under the prospect generation section of the value chain, the regulator requires geoscientist skills aimed at awarding acreage for exploration, the operating companies require geoscience skills for planning and executing exploration programmes and the service companies focus on the skills for providing exploration services.
The model develops a complete catalogue of skills required to meet the needs of all entities involved in the petroleum industry. This catalogue provides universities and training providers with skills which need to be developed in students in preparation for jobs in the industry.
Ramírez, Christian (Schlumberger) | Espinola, Oswaldo (Schlumberger) | Alvarez, Julieta (Schlumberger) | Torres, Adelfo (Schlumberger) | Avena, José (Schlumberger) | Basilio, Isaid (Schlumberger) | Guerrero, Claudia (Schlumberger)
The rich oil accumulations in the southern Tamaulipas area in Mexico have been discussed in the literature for over 100 years. The first productive well in this field located in north-east Mexico was drilled in 1910, and the field has been producing commercially since then. More than a 100 years later, in 2013, the field started a new chapter under a different operating company, which began a push for the implementation of an operations excellence initiative among the stakeholders for which the first goal is production maintenance through increased uptime of the wells.
A key to success in this new chapter for the exploitation of the field is the implementation of a digital oilfield focused in linking operational philosophy with available technologies and telemetry systems to integrate the operations excellence initiative with the field's operational requirements.
Five workflows are implemented and working for the field. Each workflow complies with a target:
Well monitoring for progressive cavity pumps (PCPs): This workflow tackles the early detection of anomalies in operational variables for well performance.
Well rate estimation for PCPs: This workflow calculates production rate estimates for PCP wells.
Well status: This workflow provides the live determination of the well operational status.
Production losses: This workflow provides the daily tracking of production performance.
Integrated reservoir and production tracking: This workflow enables field-level integrated analysis for reservoir and production data.
Incorporation of this solution generates a collaborative working environment between field operators, engineering departments and asset management, promoting synergy to strive for operation excellence in a challenging operating and economic environment.
The implementation of this digital solution enables a new era for the operations of a 100-year-old brownfield in Mexico. Changing operational conditions and low-productivity wells producing with artificial lift systems are the key challenges to maintaining production in the field. The system allows for timely acknowledgement of the field operating conditions to take proactive actions thus strengthening the operations and supporting to meet the steadily growing production targets.
The components of the system can be replicated and tailored to the challenges faced in different operating conditions. Field instrumentation, available technology, and engineering processes are combined to work toward the goal of excellence in operations and returns.
Electromagnetic (EM) heating has been proposed to recover heavy oil due to its great environmental friendliness. Previous studies focused on investigating the feasibility and enhancing the oil recovery of such non-aqueous method. However, the effect of EM heating on the variations of formation rock properties is still elusive. Detailed experiments/measurements are required to understand the effect of EM heating on changing the petrophysical properties of formation rocks.
A commercial microwave oven is used to conduct the EM heating experiments. Different types of formation rocks (shale, Berea-sandstone, tight sandstone, and Indiana-carbonate) are investigated. Various techniques, including scanning electron microscopy (SEM), energy dispersive X-ray (EDX), N2 adsorption/desorption, and X-Ray fluorescence (XRF), are used to characterize the properties of shale samples before/after experiments. The porosity and permeability measurement are performed to Berea sandstone, tight sandstone, and Indiana carbonate. An infrared thermometer is used to measure the samples’ surface temperatures. Furthermore, oven-heating experiments are conducted to distinguish the effects of conductive-heating and EM heating on the property changes of rock-samples.
Results show that different types of rocks exhibit different responses to EM heating; shale samples exhibit a higher temperature compared with sandstone and carbonate because of the better EM energy absorbance of clays and pyrite. The shale samples are crumbled into pieces or fractured after EM heating, while the sandstone and carbonate samples remain almost unchanged after EM heating. The SEM results reveal that EM heating causes tensile failure, shrinkage of clay, and release of volatile organic content to the shale sample. The N2 adsorption/desorption measurements demonstrate that the pore volume significantly increases due to clay shrinkage, while part of the pore can be blocked by the converted bituminous kerogen after EM heating. EM heating has almost no effect on Berea sandstone and Indiana carbonate due to the transparency of quartz and calcite to EM waves. However, the EM heating can fracture the tight sandstone that is saturated with water because of the rapid rise of pore pressure under EM heating.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
Hashan, Mahamudul (Memorial University of Newfoundland) | Jahan, Labiba Nusrat (Memorial University of Newfoundland) | Zaman, Tareq Uz (Memorial University of Newfoundland) | Elhaj, Murtada (Memorial University of Newfoundland) | Imtiaz, Syed (Memorial University of Newfoundland) | Hossain, M. Enamul (Nazarbayev University)
The mathematical approach is the most commonly used approach in reservoir simulation. The classical mathematical approach considers numerous impractical assumptions leading toward the development of unrealistic reservoir simulator. In contrast, recently developed engineering approach is much promising as it has numerous advantages, such as – scope of bypassing the formulation of partial differential equations and discretization of partial differential equations, the ability to avoid rigorous and complex mathematics, and capability of realistic representation of reservoir behaviour through eliminating spurious assumptions. The present study outlines the route map for developing a reservoir simulator using an engineering approach. Major challenges encountered in reservoir simulation and the fundamentals of various available modelling approaches are addressed in this paper. The outlook for both classical mathematical approach and engineering approach are reviewed along with their strengths and weaknesses. Fluid flow equations are derived based on the proposed engineering approach. To do that, a set of non-linear algebraic flow equations in the time integral form is developed using the mass balance equation, an equation of state, and a constitutive equation without going through the formulation of partial differential equations and discretization step. The time integral is then approximated to obtain the non-linear algebraic flow equations for all the gridblocks of the reservoir. The significance of the engineering approach for describing the accurate fluid flow through porous media is compared to the to conventional mathematical approach. The engineering approach provides the same fluid flow equations as the classical mathematical approach for both the radial cylindrical and cartesian coordinate system but, without going through the formulation of partial differential equations and discretization step. Much simpler ordinary differential equation solvers, e.g., Runge-Kutta method or Euler method can be used in the engineering approach to obtain the solution, whereas the classical mathematical approach does not have this advantage. Both the classical mathematical approach and the engineering approach treat the initial conditions in the same way. If classical mathematical approach uses second-order approximation then the same accuracy is obtained for both approaches in treating the boundary conditions. The engineering approach provides more precise dealing to the constant pressure boundary condition for block-centred gridding system in case of using the first-order approximation. The engineering approach gives the justification of using the central difference approximation for second order space derivative in classical mathematical approach. Results show that the proposed engineering approach based fluid flow model provides better flow prediction than the conventional mathematical approach based flow model. The outcome of this study will help engineers and researchers to develop more transparent simulator instead of creating a black box where the natural chaotic behaviour of the underground reservoir will be more understandable.
This paper analyses the results of the combined Cement Bond Log/ Variable Density Log /Radial Bond Log (CBL/VDL/RBL) tool run on 10 consecutively drilled offshore development wells by an operator during the 2015/2016 period in Trinidad and Tobago. The Bond Index (BI) is used as a quantitative criterion for measuring cement to casing bond and the VDL/RBL as a qualitative criterion for cement to formation bond. The performance of the wells after perforation is examined with the aim of highlighting the importance of a good cement job for successful production. Cement pump pressure/pump rate/cement density charts are also examined to explain cement job outcomes.
Zhao, Chaojie (China University of Petroleum) | Li, Jun (China University of Petroleum) | Liu, Gonghui (China University of Petroleum) | Zhang, Hui (China University of Petroleum) | Wang, Chao (China University of Petroleum) | Ren, Kai (China University of Petroleum) | Zhang, Xin (China University of Petroleum)
Casing deformation turned out to be serious during hydraulic fracturing of shale gas wells in Weiyuan-Channing, where the ratio of casing deformation was more than 30%. Nevertheless, there were no such phenomenon in America and other shale gas producing areas. Why there were so many horizontal wells casing deformation in Weiyuan-Changning, China? There maybe kinds of factors.
The authors mainly analyze the effect to casing deformation from operations factors during well drilling and completion, including dogleg angle, loss of cement sheath integrity and APD effect; as well as effect the geologic characteristics such as faults and natural fracture zones, lithologic interface, shale bedding.
The results show that: Firstly, though the casing strength gradually decreased as the dogleg angle increasing, the casing collapsing strength drops off only 3.8% with average 2.7°/30m dogleg angle in the casing deformation zone, which showed that it can not lead casing deformation directly. Then, though the influence of temperature and loss of cement sheath integrity will significantly reduce the safety factor of the casing, it cannot be excluded that the local cement sheath can be always damaged after hydraulic fracturing, which suggested the APD effect was not the main factor leading to casing deformation. Finally, the original stress balance near wellbore can be destroyed during multistage hydraulic fracturing leading to non-uniform in-situ stress, which can active the fault, natural fractures, lithologic interface, shale bedding to slip. Therefore there were high probability of casing deformation in the formation with faults, natural fracture zones and strong heterogeneity.
The above analysis can be used to explain why there is serious casing deformation in Weiyuan and Changning of China. Perforating far away from the point where casing deformation occurred easily and design the proper fracturing scheme can help us avoid casing deformation rather than simply raising steel grade and wall thickness of casing.
Although Trinidad and Tobago has an abundant supply of relatively pure CO2 and more than 1 billion barrels of heavy oil deposits there are no active enhanced oil recovery (EOR) projects using carbon dioxide (CO2).
In this paper, we have performed black oil simulation studies to evaluate several injection strategies with carbonated water, varying the salinity and viscosity of injected water. The salinity was varied by 1,000 and 35,000 ppm. The viscosity was increased by adding 0.1 weight percent polymer to injected water. The investigation was carried out using a commercial reservoir simulator. The simulation grid represents the properties of a quarter five-spot of the Lower Forest sand of the Forest Reserve Field. The reservoir simulation components used are water, polymer, H, Na, Cl-, dead oil, solution gas and CO2. The Stone #1 three-phase relative permeability model was used to calculate the three-phase relative permeabilities from two-phase data. In addition, a factorial experimental design was utilized and twelve simulation runs were done along with nine benchmark runs for comparison to other EOR methods.
From the results obtained the following was concluded: water salinity has no effect on either oil recovery or carbon dioxide storage; polymer injection increases oil recovery and carbon dioxide storage. We found the optimal injection strategy to be a cycling of carbonated water alternating with polymer injection.