Herskovits, Raphael (Saint-Gobain Proppants) | Kidd, Ian (Saint-Gobain Proppants) | Fuss-Dezelic, Tihana (Saint-Gobain Proppants) | Shi, Jingyu (Saint-Gobain Proppants) | Wilcox, Craig (Saint-Gobain Proppants) | Kaul, Todd (Saint-Gobain Proppants)
Today unconventional completion objectives strive toward three major goals: creating large fracture networks, placing as much proppant in those networks as efficiently as possible and ensuring fracture conductivity is sufficient to allow for maximum reservoir drainage. While operators use different, and often proprietary, completion protocols to achieve these goals, market research shows a growing trend towards the use of small mesh size proppants such as 30/50, 40/80 or even 100 mesh proppants primarily utilizing slickwater fracturing fluid systems.
Fracturing of unconventional reservoirs in this manner creates a very narrow fracture environment. This creates a completion design problem as most proppant types and sizes are qualified using 2 and 4 lb/ft2 loading conditions to simulate the wider fractures of conventional sandstone reservoirs. Further complication also lies in the fact that prior to shale development, small mesh size proppants, such as 100 mesh were very rarely used or tested as a proppant.
The study compares the mechanical strength of 40/80 white sand, 40/80 clay-based economy lightweight ceramics (ELWC) and 40/80 bauxite-based intermediate strength ceramics (ISC), as well as, 35/140 bauxite-based intermediate strength ceramic (ISC) and 100 mesh sand using standard and modified API RP 19-C crush resistance tests. During testing, load cell concentrations were varied from the standardized 4 lb/ft2 to the modified concentrations of 0.5 and 0.25 lb/ft2 – concentrations more realistic for unconventional reservoirs. Mechanical failure of proppants is quantified by comparing proppant size distribution pre- and post-stress application using a Horiba CAMSIZER. Mechanical compression of proppant packs is measured during testing and compared for different proppant types. Failure mechanism of proppants is also evaluated using an in-situ high pressure CT scanning protocol enabling visualization of the proppant failure as a function of applied load, proppant type and concentration.
The study shows that mechanical performance of tested materials, measured as proppant crush, deteriorates with decrease in proppant bed height. Deterioration of performance is, however, much less pronounced for small mesh size proppants than previously studied large mesh proppants. Contrary to that, pack compression results indicate higher compression of small mesh proppants under monolayer/thin bed conditions suggesting a large decrease in proppant pack conductivity. The most extreme pack compression is measured for 100 mesh sand proppants. In-situ CT scans also confirm these results and further visualize the effect of pack compression on proppant pack conductivity.
This paper focuses on steric filtration of hydrocarbon mixtures in nanoporous media. Molecular filtration is described by molecular partitioning between the bulk and nanopore phases. For the hindered transport of solid particles through porous material, filtration efficiency is defined based on the ratio of the solute and pore channel dimensions. This approach is not suitable for hydrocarbon mixtures because of the dependence of molecular size and shape on thermodynamic conditions. In this work, partition coefficient is determined from equilibrium thermodynamics. Flash calculations are performed to determine the fugacity ratio and the corresponding compositions of hindered components when the unhindered hydrocarbons reach equilibrium after a change in the system pressure. The differences between the original and final pressures is the filtration pressure. Two- and three-component hydrocarbon mixtures are considered with the heaviest component being the hindered component. The effect of temperature and pressure on filtration efficiency is documented and implications on improved recovery from unconventional reservoirs are discussed. According to the results filtration efficiency decreases (more hindered components pass through the pore throat) as the filtration pressure increases and ambient temperature decreases.
Dashti, L. (Kuwait Oil Company) | Filak, J. M. (Kuwait Oil Company) | Bond, D. J. (Kuwait Oil Company) | Banagale, M. R. (Kuwait Oil Company) | Al-Houti, R. A. (Kuwait Oil Company) | Luneau, B. A. (Consultant) | Molinari, D. (IFP Middle East Consulting)
The Wara reservoir is one of the main producing formations of the giant Greater Burgan field. It has been on production under natural depletion for many years. A massive water-flood of this formation has recently commenced. This was preceded by a large-scale pilot water flood the aims of which included enhancing reservoir understanding. This paper describes how historical data, including data from the large-scale pilot, were used to construct representative part filed models.
The area of the pilot water flood has significant volumes of data, including core and log data and dynamic data such as pressure transient data, interference tests, tracer tests and cased-hole logs. These provide valuable information for reservoir characterization.
The Wara formation was deposited in a tidally influenced fluvio-deltaic environment where sand continuity is complex. There was a desire to develop realistic geological and simulation models that accounted for our understanding of Wara geology and were consistent with the large volumes of surveillance data.
A major challenge was the choice of an appropriate area for the part field model. This was chosen so as to allow water influx into the area of interest over the life of the field to be accounted for and to allow relatively simple boundary conditions to be applied.
Geological models were constructed using object based techniques. These models used reservoir rock types that were developed to broadly match permeability-height estimates from pressure transient data.
The geological models were not guaranteed to account for the sand connectivity inferred form the surveillance data. A streamline based screening technique was used to exclude models that did not broadly capture the interpreted connectivity.
Dynamic simulation models were then developed and conditioned to data using conventional assisted history matching techniques. At this stage, some sensitivities related to boundary conditions were explored. Sand connectivity was not varied at this stage.
Some examples are given as to how the resulting conditioned models have been used to address questions about expected future reservoir performance. Specifically questions related to proposed well spacing and pattern type are discussed.
This paper describes a novel approach to developing models that are geologically realistic and are consistent with the interpretation of reservoir connectivity from a range of surveillance data. This involves using a streamline based screening tool before using assisted history matching techniques. Such an approach can be applied to both part and full field models.
The challenges of using such an approach with part field models are described. Some guidance is given to know when it would be appropriate to try to develop and condition part field models.
Barite is one of the most common weighting materials used in drilling fluid for deep oil and gas wells. Consequently, the main source of solids building the filter cake is the weighting material used in drilling fluids ‘Barite particles’. Barite is insoluble in water and acids such as HCl, formic, citric, and acetic acids, as well as the barite has low solubility in chelating agent such as Ethylene Diamine Tetra Acetic Acid (EDTA).
The present study introduces a new formulation to dissolve the barite filter cake using converters and catalysts. Barite can be converted to barium carbonate at high pH medium using combination of potassium hydroxide (KOH) and potassium carbonate (K2CO3) solution. Then HCl acid can be used to dissolve the barium carbonate. Another solution is to use high pH EDTA chelating agent and potassium carbonate as a catalyst/converter in one step. The removal formulation also contains polymer breaker (oxidizers). The three components of the new formulation are compatible and stable up to 300°F. Solubility tests were conducted using industrial barite particles with size ranged from 30 to 60 micron. The solubility experiments were carried at 300°F for 24 hours. Different concentrations of catalyst were added to select the optimum concentration. The designed formulation was examined to remove filter cake formed by Barite drilling fluid using High Pressure High Temperature cell (HPHT).
The result of this study showed that the barite removal efficiency of new formulation reached to 87 % in water base mud and 83 % in oil base mud. The solubility test results presented that the solubility of barite particles in 0.6M EDTA was 62 % in 24 hours at 300°F. Adding potassium carbonate catalyst to the 0.6M EDTA solution the increased the solubility of barite to 90 wt. % in 24 hours. The use of converting agents increased the barite solubility from62% to 90% in EDTA. The EDTA was compatible with the polymer breaker (oxidizer) so the filter cake removal will be in single stage. The oxidizer concentration used was 10 wt%, potassium carbonate concentration was 10 wt% and EDTA concentration was 0.6M. The new formulation achieved 85% filter cake removal in both oil-based and water-based drilling fluids. In oil base mud a water wetting surfactant, mutual solvent, and emulsifier should be added to the formulation to remove the oil. In this study, two solutions were proposed to remove the barite filter cake and barite scale from oil and gas wells at different conditions. The first one is by using HCl acid after converting the barium sulfate to barium carbonate using high pH medium such as KOH and K2CO3. Then HCl can easily remove the barium carbonate. The second method is to create the high pH medium by using the removal fluid itself which is EDTA chelating agent in addition to potassium carbonate as converter.
Technology transfer or acceptance is difficult in every industry; however, the oil & gas industry has had it especially hard with volatile commodity prices, variability of technology sources and the regulatory uncertainty. In 1994 in a paper entitled, "Development of a Model Technology Transfer Program to Assist Independent Operators"
This paper describes a program that any operator can utilize to get quick access to technology without significant costs while increasing oil production and decreasing operating expenses. This technology transfer program utilizes methods from other technology based industries yet is focused and builds upon past principals established by technology transfer programs like the Research Partnership to Secure Energy for America (RPSEA) and the Petroleum Technology Transfer Council (PTTC). This paper contains several fundamental components including: 1) Technology Leadership guided by industry to initiate and manage the technology transfer process, 2) Problem Identification activities that help create a two-way dialogue between industry and leadership organization, 3) Documented Demonstration Projects rooted in findings from problem identification activities 4) Focused Technology Workshops serving to disseminate demonstration project findings and 5) Regional Resource Centers with Outreach Resources serving as local and online repositories for easy future access by industry.
Additionally, this paper identifies various sources of research and technology development funding illustrating how an effective technology transfer process can improve the time between idea and technology commercialization. In the last few years the landscape of the oil and gas industry has changed dramatically in relation to technology. Many operators, out of necessity, have adopted a manufacturing or mass production mentality regarding their wells while disregarding optimization and the use of technology for long-term production.
This paper specifically addresses the needs of the modern oil and gas operator who does not have, or has limited access to industry research labs, government funding and university programs. It provides a step by step process designed to help operators become engaged in technology transfer in a cost-effective manner with a goal of improving their individual businesses as well as the industry at large.
A new in-situ generated HCl acid was developed to overcome the fast reaction rate and high corrosion rates of 15 wt% regular HCl acidizing system. The objectives of this work are to: (1) examine the reaction rate of the new in-situ generated HCl with calcite at 100, 150, and 200℉, and (2) compare the reaction rate of 15 wt% regular HCl with the new in-situ generated HCl.
The rate of the reaction of 15 wt% HCl and the new in-situ generated HCl was measured using the rotating disk apparatus (RDA). Calcite disks were used with the specifications of 1.5 in. the diameter and 0.65 in. thickness. The effects of disk-rotational speed (200-1,200 rpm) and temperature (100-200℉) were investigated. Calcium concentrations were measured in the samples collected from the RDA, which were used to calculate the rate of dissolution. The disk surface after the tests was analyzed using Scanning-Electron-Microscope–Energy-Dispersive Spectroscopy (SEM-EDS).
Experimental results showed that the rate of dissolution at 100 and 150°F was controlled mainly by the rate of mass transfer of the acid to the surface. By increasing the temperature to 200℉, the overall rate of reaction for the in-situ generated HCl was mass transfer limited up to 800 rpm and surface limited above 800 rpm. Based on the dissolution rate results, the diffusion coefficient, the activation energy, and the reaction rate constant at 100, 150, and 200°F were determined for the new developed in-situ generated HCl and were compared to 15 wt% regular HCl.
This study will assist in developing a more cost-effective and efficient design of acid treatments through a slower reaction rate of the in-situ generated HCl. This new in-situ generated acid system reacts slower and more efficient compared to regular HCl in carbonate and sandstone reservoirs.
Co-injection of CO2 or light hydrocarbons with steam in SAGD (Steam Assisted Gravity Drainage) process may enhance bitumen mobility and reduce Steam Oil Ratio (SOR). Understanding and modeling the phase behavior of solvent-bitumen system are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and modeling study is undertaken to characterize the phase behavior of bitumen-CO2 and bitumen-C4 systems. Produced and dewatered oil from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater formation. Constant composition expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2-bitumen mixture, and C4-bitumen mixture. The Peng-Robinson equation of state (PR-EOS) is calibrated based on the measured data and used for PVT modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 120 °C to180 °C. Further to that, dead oil viscosity measurements are conducted at similar temperature intervals to estimate oleic phase viscosity.
According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than CO2 at reservoir pressure of 580 psia (4,000 kpa) and temperature range of 120 °C to 180 °C. During the CCE tests, co-existence of three equilibrium phases is observed for the C4-bitumen system with 84 wt.% C4. The three phases consist of a solvent-lean (bitumen-rich) oleic phase (L1), gaseous phase (V) and a solvent-rich (bitumen-lean) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into L2 phase and preserve the heavy components in L1 phase. It is observed that the color of L2 phase becomes lighter by decreasing the pressure which may suggest extraction of lighter hydrocarbon components at lower pressures. Similar tests on the CO2-bitumen system only shows two effective phases over a similar temperature range. The two phases consist of a solvent-lean (bitumen-rich) oleic phase (L1) and a gaseous phase (V).
By using the regressed EOS model, phase equilibrium regions are predicted in the compositional space for the solvent-bitumen system. EOS predictions indicate two types of two-phase regions in composition space for C4-bitumen system (i.e., L1-L2 in temperature range of 120 °C to 148 °C and L1-V in temperature range of 148 °C to180 °C). However, only one type of two-phase region (i.e., L1-V) exists in the similar temperature range for CO2-bitumen system. The EOS predictions show that 1.7 wt.% CO2 can reduce bitumen viscosity by up to 4 times, and 8.7 wt.% C4 can reduce bitumen viscosity by up to 32 times in temperature range of 120 °C to 180 °C.
Electrical submersible pump (ESP) technology has evolved to become a critical component in many production operations and well productivity enhancement. However, one of the important challenges in real-time ESP-enabled well management is the implementation of intelligent systems that can assist human operators in making control decisions. Modern technological advances have resulted in increasingly complicated processes that present considerable challenges in performance analysis and well management for successful operation of electrical submersible pumps. Given the size, scope, and complexity of modern engineered electrical submersible pump systems, it is becoming significantly more difficult for engineers to anticipate, diagnose and control serious abnormal events in a timely manner. Failure of the operator to exercise the appropriate mitigation actions often has an adverse effect on the process safety quality, run life, surface hardware and downhole equipment. Hence, there exist considerable incentives to develop intelligent alarm systems for automating electrical submersible pump system parameters estimation and optimization. The difficulties associated with implementing intelligent alarms and the opportunities for improvements are even greater in the advanced wells equipped with electrical submersible pumps due to complex flow and transport process challenges.
In this paper, a state estimator is implemented in the form of data assimilation algorithm using a variety of data-driven models and continued ESP operations performance properties measurements. The data assimilation3 estimates continuously the state variables of the data-driven ESP models to provide a feedback to an online intelligent alarm monitoring system. The intelligent alarm surveillance system workflow combines streaming surface controller data, well head data and sensor data to intelligently define thresholds and determine when a given measurement is out of range and human intervention is needed. Further multi-signal data analysis is employed to characterize given events and perform dynamical optimization (based on define objective functions and operations constraints) for recommending real-time controller set point updating and corrective actions during real time ESP operations. Such optimization framework has the potential to improve production while simultaneously providing cost savings by reducing remote human intervention and the deployment of personnel to field locations.
The web-based alarm surveillance system has been successfully tested in multiple fields to verify the functionalities of the alarming system. Numerous abnormal events were identified in the field and faults signatures and trends were stored in the knowledge database along with the corresponding alarm mitigation strategy. The smart alarming produces superior results in several case studies performed on multiple Permian basin wells and fields. This new smart alarming approach will greatly help in the increasing real time artificial lift ESP management over existing conventional basic ESP alarm monitoring methods.
This paper describes the development and testing of an innovative downhole zonal pressure maintenance device (PMD) developed for open and cased hole well completions. This PMD will be deployed as an integral tubular component in a generation IV single-trip multizone sand control system (STMZ) currently run in deep water and in other unconsolidated soft-rock applications. It will significantly increase the system's capability and provide proven time-saving benefits of such technology into the soft-rock formation arena.
Typical generation IV systems currently used isolate the discrete zones from one another and the wellbore. The operational steps include setting the top-most packer first. This process isolates the zones from the hydrostatic overbalance pressure, creating an opportunity for uncontrolled crossflow among zones with differing bottomhole pressures. This crossflow can, and will, move hydrocarbons as well as formation sand into the wellbore therefore certain limitations are placed on the existing STMZ system. The PMD maintains the initial hydrostatic pressures on each zone independently to help prevent uncontrolled crossflow and its detrimental effects. The PMD construction is totally mechanical and fully autonomous, not requiring any signals from the surface for its operation. It has built-in intelligence to sense the array of initial hydrostatic pressures in various zones and to store them for subsequent use.
Prototype tools were developed and tested in the laboratory, simulating near realistic multizone completion operations. The PMD design enables the amount of fluid leakoff into the formation to be minimized, thereby reducing formation damage. This capability is accomplished by automatically adjusting the PMDs to the respective zones to reflect the individual differences in reservoir pressure; it is particularly useful for completing wells wherein significant differential pressure exists between compartments because of the depletion that has occurred in some reservoirs.
The paper illustrates expected results on a multizone completion and displays the pressure maintenance behavior resulting from the use of this device.
Tests were conducted in the laboratory to validate the tool performance under extreme conditions of high leakoff rate in conjunction with an abrasive fluid with plugging tendency (oil-based mud). Another condition simulated relatively high pressure differential (2,000 psi) while reversing out after a "frac pack" operation.
The tool design incorporates state-of-the-art technologies, such as 3D printing and hydraulic miniaturization using implementation techniques unique to oilfield applications. Generation IV single-trip multizone system technology has been a key enabler for formations, such as those found in the Lower Tertiary of the Gulf of Mexico. The PMD provides a novel tool to extend these multizone applications to unconsolidated formations and to multizone reservoirs with high reservoir pressure differentials.