Search

This study investigates the performance of viscoelastic surfactant (VES)-based HCl stimulation fluids as a function of carbonate rock type and quantifies the response of the acid to different pore-structures. A pore-structure evaluation during stimulation design could lead to a successful field treatment. Coreflood tests were conducted using several types of limestone cores with permeabilities ranging from 2.5 to 155 md. Intergranular pores were dominant in the Indiana limestone and Austin chalk samples investigated, whereas moldic pores were dominant in the Pink desert, Edwards yellow, Winterset, and Edwards white cores. Tracer experiments characterized the pore structure in each carbonate sample, and the tracer fluid was injected at 5 cm3/min and 75°F into the cores with dimensions of 6 in. length and 1.5 in. diameter. The tracer effluent data was used to measure accessible porosity (flowing fraction) for each core sample. After the tracer, the VES acid was injected at rates from 1 to 10 cm3/min and 150°F to determine pore volume to breakthrough (PVbt). The wormhole patterns were analyzed using computed tomography (CT) scan images, and the pattern complexity was examined by fractal dimension analysis. A better pore connectivity showed for Indiana limestone compared to Edwards yellow, Winterset limestone, and Edwards white. The flowing fractions were 1, 0.86, 0.61, and 0.53 for Indiana limestone, Edwards yellow, Winterset limestone, and Edwards white, respectively. The PVbt of Indiana limestone ranged from 0.62 to 0.92. Cores with lower pore connectivity, such as Edwards yellow, had PVbt ranging from 0.52 to 0.81, Winterset limestone from 0.34 to 0.49, and Edwards white from 0.21 to 0.36. These results revealed that higher flowing fractions are required with a higher PVbt. Rocks that have the same dominant pore-structures usually exhibit similar wormhole behavior. Prior to this study, the performance of VES fluids had only been studied on carbonate rocks with well-connected intergranular porosity. The results of this study show that porosity distribution of the rock affects the response to acids.

Objectives The objective of this paper is to calibrate porosity and permeability derived from NMR logs to core measurements and thus allow improved porosity and permeability prediction from new and historic NMR logs. Permeability, and to a lesser extent porosity, are the most important parameters in determining the potential production of a reservoir. Measuring these parameters accurately is challenging in carbonate formations due to heterogeneity and the wide variety of pore classes, such as interparticle porosity, moldic porosity, vuggy porosity, and microporosity. Traditional density-neutron and sonic tools used to measure the porosity are strongly dependent on lithology which might yield incorrect porosity measurements. NMR logs, while largely independent of matrix properties, can potentially underestimate microporosity. No wireline tool is capable of continuous permeability logging. Methods In this study, we provide an assessment of NMR measurements at laboratory and reservoir conditions to allow improved estimation of porosity and permeability. The formation under investigation is largely limestone, with negligible dolomite or clay – but has a large range of pore structures. Several samples from different rock types were selected for this study. These were investigated with computed tomography scanning, thin section analysis, and high pressure mercury injection capillary pressure (MICP) tests. NMR T1 and T2 measurements on fully formation water saturated samples were then conducted at laboratory and reservoir conditions. Finally, to define the bound and free water, and determine appropriate T2cutoff(s) for each rock type, samples were desaturated to irreducible water saturation (Swi) using a centrifuge technique, followed by NMR T1 and T2 measurements at Swi at reservoir conditions. Additionally, the laboratory NMR measurements are compared to wireline log NMR measurements at the same depths. Results Pore size distributions from NMR measurement agree well with those derived from MICP tests. The NMR measurements on desaturated samples showed that Swi and the corresponding T2cutoff vary from sample to sample. Possible controls on this will be discussed. The results from this study showed that T1 measurements confirm T2 responses: both are strongly dependent on temperature, but less dependent on pressure. Novel Information A strong 1 to 1 correlation between helium porosity, φHE and NMR porosity, φNMR was observed demonstrating that in this formation under recording of microporosity is not an issue. Based on NMR data, permeabilities were calculated using both the Coates and SDR models. It was found that the Coates model gives good agreement with permeabilities measured on core plugs by the standard laboratory techniques.

The invasion and movement of drilling fluids through shale formations can significantly contribute to wellbore instability. By combining the experimental results with the microstructural studies of core samples, we will examine the invasion and movement of fluids in shale formations near wellbore, including the mechanisms, rates, affecting factors, and impact on shale stability. Pre-test core studies provided insight into rock composition, structure, fracture distribution, water activity, and pore-fluid composition. Pore-fluid transmission tests were conducted on preserved shale cores from four different formations, each with a different water activity measurement. Thin section analyses of post-test cores were conducted to evaluate shale-fluid interactions and the impact of fluid invasion and movement on shale stability. Test results show clear evidence of a reverse osmosis process out of the shale. The reverse osmosis increased when the difference between the water activity of the shale's pore fluid and the drilling fluid also increased. A water activity difference of >0.07, and the resulting pore-pressure drop (caused by the reverse osmosis), can subdue the impact of fluid invasion from drilling fluid to formation and led to a net decrease in downstream pressure. Reverse osmosis could cause downstream pressure below the initial value in a few minutes. A pore-pressure drop due to reverse osmosis may improve the stability of wellbore due to an increase in effective drilling fluid support. However, tests show that strong reverse osmosis could cause fracturing from over-dehydration of the shale. Tests also indicate that invasion along fractures increases pore pressure, even with a potential for strong reverse osmosis. Adjusting the water activity of drilling fluids to closely match that of the shale formations while minimizing fluid invasion along fractures and other fluid channels reduces wellbore instability.

In highly heterogeneous carbonate reservoirs, several acid systems have been used to enhance acid distribution during matrix acidizing. Gelled acids are commonly used to improve the wellbore coverage. However, the injection of such acids at low rates and high temperature has a negative effect on spending rate, initiates filtercake formation which inhibits the wormhole growth, can cause formation damage and has high corrosion rates. This paper presents an innovative formulation for emulsifying the gelled acid (polymer assisted emulsified acid) for better acid treatments at high temperatures. The objective of this work is to investigate the behavior and the performance of a new innovative acid system: polymer assisted emulsified acid as a self-diverting acid by conducting viscosity measurements, reaction rate experiments, thorough coreflood study, and acid diversion experiments. The system was 15 wt% gelled acid emulsified in diesel with 70:30 acid/diesel volume ratio. Coreflood experiments were conducted at 230°F at different injection rates on low and high permeability Indiana limestone. Also, a 0.5 PV of the polymer assisted emulsified acid was injected to assess the effect of the acid on the permeability of the cores before breakthrough. Finally, two acid diversion experiments at 1 cm3/min were conducted into pairs of low and high permeability cores to test the effect of polymer concentration in the acid internal phase on diversion. The viscosity measurements and acid diffusivity measurements showed that increasing the polymer concentration in the internal phase of the emulsified acid from 0 to 1.5 vol% enhanced significantly the viscosity of the emulsified acid and reduced the diffusion coefficient by one order of magnitude. Coreflood results showed that the polymer assisted emulsified is an effective wormholing fluid at low injection rate while maintaining the high viscosity of the acid system for zonal coverage. Also, it was shown that the emulsion/polymer retention is the main source for permeability damage. However, flowback with mutual solvent removes any remaining damage and permeability enhancement is achieved Acid diversion experiments were presented that show the self-diverting ability of the polymer assisted emulsified acid into the low permeability cores.

Carbonate formations are very complex in their pore structure and exhibit a wide variety of pore classes. Pore classes such as interparticle porosity, moldic porosity, vuggy porosity, intercrystalline porosity, and microporosity. Understanding the role of pore class on the performance of emulsified acid treatment and characterizing the physics of the flow inside is the objective of our study. The study was performed using vuggy dolomite cores that represent mainly the vuggy porosity dominated structure, while the homogenous cores represent the intercrystalline pore structure. Core flood runs were conducted on 6 × 1.5 in. cores using emulsified acid formulated at 1 vol% emulsifier and 0.7 acid volume fraction. The objective of this set of experiments is to determine the acid pore volume to breakthrough for each carbonate pore class at different injection rates. In this paper, a novel approach to interpret the core flood run results using thin section observations, tracer experiments, SEM, and resistivity measurements will be presented. Thin section observations provide means to study the vugs size and their distribution, connectivity, and explain the contribution of the pore class in the acid propagation. Relating the rotating disk experiments of emulsified acid with dolomite to our core flood run results will be also conducted in order. The acid pore volumes to breakthrough for vuggy porosity dominated rocks were observed to be much lower than that for homogenous carbonates (intercrystalline pore structure). Also, the wormhole dissolution pattern was found to be significantly different in vuggy rocks than that in homogenous ones. Comparison of thin section observations, tracer results and the core flood runs results indicates that the vugs are distributed in a manner that creates a preferential flow path which can cause a rapid acid breakthrough and effective wormholing than those with a uniform pore structure. Rotating disk experiment results, demonstrating that the reaction of emulsified acid with dolomite is much lower than that with calcite, showed that the reaction kinetics played a role in determining the wormhole pattern.

The main objective of well stimulation has been to create wormholes or fractures in order to bypass the damaged zone and enhance the permeability in the near-wellbore area. Regular HCl was the main stimulation fluid. However, at high temperatures, both reaction and corrosion rates become very high and regular HCl loses its advantages. There are many alternatives for regular HCl; emulsified acid is one of the available alternatives for regular HCl. In the present work, an emulsified acid system was used formulated using a cationic surfactant. This system was tested using reservoir cores obtained from a carbonate reservoir. The core samples were analyzed using CAT scan to study the presences of vugs or channels, and to determine the presence of anhydrite. Small samples of the cores were analyzed using the SEM technique. A series of core flood tests were conducted using 15 wt% HCl emulsified acid systems formulated using 1.0 vol% emulsifier. The acid volume fraction was 0.7, and all experiments were performed at temperature of 220°F. The acid injection rate ranged from 1.0 to 10 cm3/min. After acid treatment is accomplished, the cores were CAT scanned to study the number and distribution of wormholes. Samples of the effluent fluid were collected during the core flooding experiment. These collected samples were analyzed using the ICP, to determine the calcium and magnesium concentrations. The CAT scan of the cores obtained from a carbonate reservoir showed a great heterogeneity. The static test for solubility of rocks in regular 15 wt% HCl, indicated that the rocks has a high solubility in acid and the need to use an effective retarded acid system. From the coreflood study, there is an optimum injection rate for an emulsified acid system when it was tested reservoir cores, and it was found to be in the range from 5 to 7 cm3/min. The emulsified acid system can be used effectively, with no face dissolution, at low and high injection rates. For high permeability cores, the final permeability enhancement (ratio of final to initial permeability) increased with increasing the injection rate.

The use of Horizontal well has been increasing very rapidly throughout the oil industry and its applicability is now extended to the secondary and tertiary recovery processes. In this paper, a study on mature oil field case has been made to assess the technical feasibility of miscible gas injection using horizontal wells and to investigate the impact of gas injection horizontal wells on ultimate oil recovery. A reservoir model using 3-D compositional equation of state simulator is built to carry out different development scenarios to optimize the field development and increase the oil recovery using miscible gas injection process. The model is used to investigate the impact of using different combinations of horizontal and vertical injection and production wells on the performance of the process. The impact of alternative development scenarios on oil recovery, plateau oil production rate, and fluid saturation distribution are evaluated. The results show that the use of horizontal gas injection wells resulted in increase in cumulative oil recovery and gives better sweep efficiency. A sensitivity study is also presented in this paper to evaluate the parameters that affect the performance of the horizontal well pattern used in miscible gas injection process. The study emphasized on the horizontal permeability, permeability anisotropy, horizontal well length. From the simulation results, the model is found to be most sensitive to permeability anisotropy followed by horizontal permeability then to horizontal well Length. Thus it is recommended that these parameters must be properly estimated prior to use in simulating miscible gas injection process using horizontal well pattern.

Injection pressure fall-off (PFO) test analysis has proven to be a reliable vehicle for understanding and evaluating well performance. Recently the methodology has been extended to the understanding of injectors. This paper presents an optimization model for analysis and interpretation of PFO tests for fractured water injectors. An elliptical composite flow model mathematically represents the fractured injector well. The optimization scheme couples the mathematical model of the well with a Genetic Algorithm (GA) to reach the final solution. The pressure transients representing the behavior of an injector a closing fracture and the discontinuity in fluid mobility are best developed in elliptical coordinates. The methodology derives the dimension of the induced fractures, formation permeability, fracture conductivity and fracture face skin. The current paper illustrates the solution methodology by showing the attained match for a West Africa offshore field case. The field case provides reasonable agreement for the fracture dimensions and characteristics as verified by other techniques. Genetic Algorithms are one of the most common artificial intelligence techniques for optimization. The reported solution is obtained by applying a GA with a non-linear least square error function as an objective function. A special penalty function, mutation, crossover probabilities, and stopping criterion are used to obtain the global minimum of the objective function. The test data analysis is done through type curve matching of the pressure and its derivative by minimizing the objective function to help determine the parameters that provide the best match between the field data and the presented novel fractured injector type curves.

Predicting the performance of wells in stress-dependent gas reservoirs can be quite challenging to most conventional reservoir engineering tools. In this paper, a fully coupled geomechanics and fluid flow analytical model was developed for modeling well performance in stress-dependent gas reservoirs. For tight and unconsolidated gas reservoirs that exhibits variable formation compressibility, reservoir compaction, and stress-dependent properties deterioration such as permeability and porosity, the geomechanics effect may not be ignored. All these physical contributes play an important role on well performance. The coupled model considered all these contributes and evaluate their impact on well productivity. The model also accounts for the effect of the transient flow period and variable producing conditions in addition to the effect of non darcy flow in gas wells. An optimization algorithm was used with the coupled model to estimate original gas in place and performance characteristics for each layer in case of multilayered gas reservoirs. Different simulation cases and selected examples from gas wells producing from stress dependent gas reservoirs are used to illustrate the coupled model application. The results from this study indicates that a fully coupled geomechanics and fluid-flow modeling approach is necessary for analyzing highly stress-sensitive gas reservoirs