Molina, Oscar M. (Louisiana State University)
Frac hits relates to the problem of newly created hydraulic fractures interacting with either primary and/or secondary fractures from offset wells. This fracture-driven interaction (FDI) represents a major concern for shale oil and gas producers given that infill wells experiencing frac hits typically underperform parent wells landed in the same zone. In addition, the sudden pressure communication established through frac hits between multi-fractured horizontal wells (MFHW) can result in damage to parent wells.
In this work, we introduce an analytical model to detect frac hits and assess the fraction of primary fractures connected between the infill and offset well. We assume that frac hits are due to overlapping primary fractures. Frac hits are modeled as a valve between MFHWs that allows certain degree of pressure communication. While the aperture of this valve is controlled by the number of frac hits, the leakage rate is governed by the bottomhole pressure (BHP) differential between wells.
The analytical solution to the fluid-flow model is derived in Laplace domain and is inverted numerically. We found that BHPs are coupled via the degree of interference coefficient δw, defined as the ratio of frac hits to the total number of primary fractures of the infill well. We utilize δw to history-match the analytical model with numerical data. As a result, history-matched δw delivers an estimate of the actual fraction of frac hits ((Equation)).
We study several sensitivity analyses to examine the impact of variation in MFHW properties on the accuracy of the estimation of (Equation) via δw. In general, our model gives an accurate estimation (Equation) for most of the cases evaluated in this work; however, we see that the analytical model may introduce significant error in the estimation of frac hits when SRV and matrix permeability are the same order magnitude. Type-curves for rate-normalized data as well as (Equation) vs δw tables are discussed herein. The computational script used for the analytical calculations in this work proved to be efficient and straightforward to implement.
Injection profiling in multilayer (stratified) reservoirs is essential for successful water flooding and effective reservoir management. When possible, injection profiling may be achieved via production logging tools (PLT). An alternative approach is to utilize real-time temperature monitoring e.g. via fiber optic distributed temperature sensing (DTS) to obtain the injection profiles. Development of modelling tools is required to enable analyzing temperature data for injection profiling.
In this work, an analytical solution is developed to determine the transient temperature distribution inside the reservoir during the warm-back period that follows cold fluid injection. The analytical model is used to introduce a temperature inversion approach to obtain the injection profile. The analytical solution is developed for single- and multi-layer reservoirs considering single-phase flow at constant rate over the injection period. The solution considers heat transfer by conduction and convection during the injection period. Warm-back is attained during the subsequent shut-in period through heat transfer by conduction inside the reservoir (thermal equilibration) as well as the heat exchange between the completed layers and the surroundings. Heat transfer with the surrounding layers can affect the warm-back rate of swept region during the shut-in period especially for relatively thin layers. The new solution is verified through comparison against numerical simulation results obtained using a thermally coupled numerical simulator for single- and multi-layer reservoir cases. Graphical interpretation technique is introduced by translating the analytical solution into a convenient form. The graphical technique is applied to synthetic warm-back data to illustrate its reliability and accuracy in obtaining the injection profile and the thermal front extent (per layer) during the injection period.
This study is based on the premise that most of the trapped hydrocarbons can be produced, if we substitute them with another ‘acrificial’ fluid that has amplified interactions with organic pore walls, such as CO2. For the presented study, a downhole shale sample is analyzed in the laboratory to predict gas storage properties such as pore-volume, pore compressibility, and gas adsorption capacity. Then a series of pressure pulse decay measurements are performed to delineate transport mechanisms and predict stress-sensitive permeability. These coefficients are obtained as the calibration parameters of a simulation-based optimization for injection and production. Simulation model considers compositional gas flow in a deformable porous media and includes a multi-continuum porosity, with organic and inorganic pores, and micro-fractures. The experimental and simulation results show that most of the injected CO2 is adsorbed in the organic matrix and are not produced back. This is because CO2 molecules have significantly larger adsorption capacity when compared to methane. The strong adsorption of CO2 improves the release of natural gas from kerogen pores. This indicates that the separation of produced CO2 will be a minimal cost. Transport in kerogen has significant pore wall effects, and includes large mass fluxes of the adsorbed molecules by the walls due to surface diffusion. In essence, the adsorbed CO2 molecules significantly influence transport of methane. The results also show core-plug permeability is stress-sensitive due to presence of micro-fractures. Forward simulation results using optimum parameters indicate that closure stress developing near the fractures could significantly control the volume of CO2 injected. This raises operational issues on when to start injecting, and how to inject CO2. Using a simulation study of a production well with single-fracture, we show that fracture closure stress develops rapidly and production rate becomes a slave of the fracture geo-mechanics, e.g., strength of the proppants and the level of proppant embedment.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
To date, our feasibility studies [CMTC-502487-MS and SPE-190163-MS] of the Gad and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process for the South Rumaila oil field have considered using Carbon Dioxide gas injection to enhance recovery from the field. As availibiulity of CO2 is limited and its cost considerable it might be also feasible to use natural gas,, Associated Produced Gas (APG) as an alternative solvent to enhance oil recovery with this process. In the study, efficiency of APG vs. CO2 is compared for the South Rumaila oil field.
In the study, the GDWS-AGD process installation includes 20 vertical APG injection wells are drilled to the top of the reservoir to build a gas cap in the oil pay zone. In addition, eleven horizontal oil-producing wells are placed at the bottom of the oil pay zone with six horizontal water drainage (sink) wells below the oil-water contact (OWC). The two horizontal leg installation may be made from a vertical well with 7-casing dual-completed (from two kick-off points) in the oil payzone and in the bottom water (below OWC) with two horizontal well legs and the two 2-3/8 inch tubings in each well. In a dual-tubing design of the process the two horizontal well legs produce independently. If only one tubing is used production from the water sink well is hydraulically isolated inside the vertical well by a packer. In either design, the water sink well is operated with a submersible pump.
In this study, the GDWS-AGD process with APG is considered for the upper sandstone member/South Rumaila Oil Field, located in Iraq to improve oil recovery. The Rumaila field has an infinite acting-aquifer with very strong edge water drive. In the GDWS-AGD, the bottom water drainage would not only reduce water cut and water cresting, but would also significantly reduce the reservoir pressure, resulting in improving gas injectivity. The study shows considerable improvement with the GDWS-AGD process - oil recovery increased from 76% by CO2 to 83% by APG and water cut was readily controlled resulting in more rapid reduction with APG (from 98% to less than 5%) than that with CO2 in all horizontal oil producers. The results show that the use of APG gas alternative for the GDWS-AGD process not only improves water-cresting control due prompt reduction of water cut, but also enhances gas injectivity and significantly improves oil recovery.
The significant temperature difference between the fractured and non-fractured regions during the stimulation fluid flow-back period can be very useful for fracture diagnosis. The recent developments in downhole temperature monitoring systems open new possibilities to detect these temperature variations to perform production logging analyses. In this work, we derive a novel analytical solution to model the temperature signal associated with the shut-in during flow-back and production periods. The temperature behavior can infer the efficiency of each fracture. To obtain the analytical solution from an existing wellbore fluid energy balance equation, we use the Method of Characteristics with the input of a relevant thermal boundary condition. The temperature modeling results acquired from this analytical solution are validated against those from a finite element model for multiple cases.
Compared to the warm-back effect in the non-fractured region after shut-in, a less significant heating effect is observed in the fractured region because of the warmer fluid away from the perforation moving into the fracture (after-flow). Detailed parametric analyses are conducted on after-flow velocity and its variation, flowing, geothermal, and inflow temperature of each fracture, surrounding temperature field, and casing radius to investigate their impacts on the wellbore fluid temperature modeling results.
The inversion procedures characterize each fracture considering the exponential distribution of temperature based on the analytical solutions in fractured and non-fractured regions. Inflow fluid temperature, surrounding temperature field, and after-flow velocity of each fracture can be estimated from the measured temperature data, which present decent accuracies analyzing synthetic temperature signal. The outputs of this work can contribute to production logging, warm-back, and wellbore storage analyses to achieve successful fracture diagnostic.
Renato P. Coutinho and Paulo J. Waltrich*, Louisiana State University Summary In this paper we describe using a commercial transient multiphase-flow simulator to develop a new operational procedure for liquidassisted gas lift (LAGL) unloading. The simulation model is used in our study to perform sensitivity analysis on the controlling parameters for the LAGL unloading operation. This simulation model is validated with experimental data from field-scale test data presented by Coutinho et al. (2018). From the simulation results and experimental data, it is possible to demonstrate how the injection of a gas/liquid mixture can significantly decrease the injection pressure for unloading operations. Different combinations of injection gas/liquid ratio are numerically tested to evaluate the effect of gas/liquid ratio on the injection pressure during the complete unloading operation. The validated model was used with a newly developed procedure for the complete unloading operation. The modeling results show that using the LAGL technique enabled us to reduce the injection pressure from 1,200 psig, when using single-phase gas in a singlepoint injection system, to approximately 700 psig, when injecting gas/liquid mixtures in a single-point injection system. Analyses on the effect of gas lift valve-orifice size, also presented here, show that using large orifice sizes might reduce the effect of flow friction through the gas lift valve, which directly affects the efficiency of the LAGL unloading operations. As part of the gas lift technique, heavy fluids (e.g., reservoir or completion fluids) need to be lifted out of the casing and production tubing to start or reestablish production. This fluid-removal process is known as wellbore unloading. The kickoff injection pressure is kept low to reduce compression power (Capucci and Serra 1991), which is directly related to the reduction of compressor size and compression cost. Empirical methods are often used to determine the vertical position of the gas lift valves.
This paper investigates the effects of high production rates on well performance for a casedhole gas well using two types of completion schemes: frac pack and gravel pack. We model fluid dynamics in the near-wellbore region, where the most dramatic changes in pressure and velocity are expected to occur, using computational fluid dynamics (CFD). The fluid-flow model is dependent on the Navier-Stokes equations augmented with the Forchheimer equation to study inertial and turbulence effects in regions where the velocity increases and decreases sharply over a relatively small length scale. Real-gas properties are incorporated into the momentum-balance equation using the Soave-Redlich-Kwong (SRK) equation of state (EOS) (SRK-EOS). The near-wellbore model is pressure-driven under steady-state and isothermal conditions. Well-performance curves are generated depending on simulation results for both completion schemes. Furthermore, we introduce the concept of rate-dependent pseudoskin factor to assess inertial and turbulence kinetic energy (TKE) losses under various pressure differential. Analysis of the simulation results suggests that the rate-dependent pseudoskin changes from negative at low gas-production rates to positive at medium-to-high gas-production rates. This is primarily because of the inertial and turbulence effects being triggered at a certain flow rate, which we define as the optimal operating point. We demonstrate that the gas-deliverability curve plotted along with the pseudoskin-factor curve allows us to estimate the optimal operating condition as the point where the rate-dependent pseudoskin is zero. An analytical model to estimate the optimal production rate is proposed as an extension to typical multirate tests.
Previous experimental studies show that nanoparticle-stabilized supercritical CO2 foams (or, NP CO2 foams) can be applied as an alternative to surfactant foams, in order to reduce CO2 mobility in gas injection enhanced oil recovery (EOR). These nanoparticles, if chosen correctly, can be an effective foam stabilizer attached at the fluid interface in a wide range of physicochemical conditions.
By using NP CO2 foam experiments available in the literature, this study investigates the applicability of NP foams for mobility control and thus improved sweep efficiency. This study consists of two tasks: (i) presenting how a population-balance mechanistic foam model can be used to fit experimental data and determine required model parameters, and (ii) examining sweep efficiency in a condition similar to Lisama Field (a 5-spot pattern with 4 producers and 1 injector in the middle), by using relevant gas mobility reduction factors derived from mechanistic modeling technique. The field-scale simulations are conducted with CMG software, contrasting NP and surfactant foams (in both dry and wet foam injection conditions) to gas only injection and gas-water coinjection (no foam).
The results show how the model can successfully reproduce coreflood experimental data, creating three different foam states (weak-foam, strong-foam and intermediate states) and two steady-state strong-foam regimes (high-quality and low-quality regimes). When the gas mobility reduction factors ranging up to 10 from the model fit are applied in the field-scale simulations, the use of nanoparticles improves oil recovery compared to gas-water co-injection, but not as efficient as successful surfactant foam injection does. This implies that although nanoparticle-stabilized foams do provide some benefits, there still seems some room to improve stability and strength of resulting foams.
The large variations in temperature and pressure conditions that prevail in deepwater operations have drastic effects on the rheology of drilling fluids used. Under such conditions, rheological properties of oil-based drilling fluids could be detrimentally affected. The main reasons of the aforementioned include; the high sensitivity of its organic phase thermal expansion (compression) coefficient and its large viscosity buildup observed with decreasing temperatures. The consequences on drilling hydraulics may include high surge/swab pressures, poor hole cleaning, and the potential of substantial errors in estimated static and equivalent circulation densities; thereby compromising well integrity.
Rheological models used to fit flow curve data of drilling fluids from commonly used field instruments such as the Fann viscometer, do not capture wall slip phenomenon prevalent in highly concentrated suspensions and emulsions as a result of the no-slip boundary condition in their constitutive equations. This could mean significant errors in the derived drilling hydraulic parameters for fluids displaying wall slip.
In this study, water-based (WBM) and oil-based mud (OBM) samples were prepared using different surfactants and their rheology was characterized using a Fann 35 viscometer and MCR 52 rheometer at temperatures ranging from 10 – 75 °C. This was done to highlight differences in frictional pressure loss estimations between a commonly used field instrument and a higher precision rheometer for muds displaying wall slip behavior. The shearing gaps used in the investigation were 1.17 mm for the Fann 35 viscometer and 0.5 – 2.0 mm for the MCR 52.
Wall slip behavior of the mud samples, as well as discontinuous shear thickening due to jamming of dispersed particles, was found to affect agreement in flow curve measurements between both instruments. For set well depth and environmental conditions, lower frictional pressure losses and cuttings transport efficiency were determined for samples showing high levels of wall slip, particularly at high temperatures. The importance of the outcome is underscored by its importance to the successful and timely completion of the wells, as well as total equipment cost.