Gomaa, Ahmed M. (EXPEC-Advanced Research Center) | San-Roman-Alerigi, Damian P. (EXPEC-Advanced Research Center) | Al-Noaimi, Khalid R. (EXPEC-Advanced Research Center) | Al-Muntasheri, Ghaithan A. (EXPEC-Advanced Research Center)
Proppant selection and placement have been significantly discussed in the literature as the key parameters to measure the success of a hydraulic fracturing treatment. Conventional proppant pack may suffer a significant reduction in conductivity due to gel damage, fines migration, multiphase flow, and non-Darcy flow. To mitigate these adverse effects, an alternative posits to substitute the porous proppant pack in the fracture with an isolated structure made of propped pillars surrounded by a network of open channels. However, recent field data has not shown improvement in the productivity of the well due to channel creation within the fracture geometry.
The objective of this study is to understand the effect of proppant permeability, placement, and channel creation on the well productivity using the numerical technique. A 3D numerical model was constructed to simulate the hydrocarbon flow from the reservoir through the fracture towards the wellbore. Production rate, well productivity index (PI), and dimensionless well productivity index (Jd) were evaluated as a function of the following parameters:
For conventional proppant pack, numerical results agreed with Cinco-Ley and Samaniego-V (1981), and it showed that dimensionless fracture conductivity (CFD) values higher than 30 maximize Jd. Also, the numerical model revealed that pillar fracturing technology with highly conductive channels could significantly improve well productivity if the used proppant conductivity is low. However, for high proppant conductivity and high CFD values, the maximum increase in well productivity index due to channel creation will be only 20%. For low CFD values, pillar fracturing technique with highly conductive channels is highly recommended, particularly if the vertical to horizontal permeability ratio is low.
Statistical analysis of the numerical results evinced that reservoir permeability and near-wellbore proppant conductivity have a major effect on the well productivity; whereas proppant conductivity in the far-field region has limited effect. The statistical analysis revealed that any number of channels greater than 2 has marginal influence on the well productivity and that the derived, dimensionless, variables can be used to create conditional decision models to maximize it. The results suggest that there is an interplay between the dimensionless fracture conductivity and the near-to-far-field permeability ratio that has a significant influence on the results.
This paper will present a Coiled Tubing (CT) technology that can be used to maneuver severely washed-out open hole sections. The presence of open hole washouts is known to restrict access to pay zones during reservoir monitoring or other well intervention operations. The case study of the paper is a water injector completed with a 6-in. open hole across the pay zone. The lithology of the first 30 ft of the open hole section contains anhydrite. Due to prolonged exposure to injection water, leaching of the anhydrite layers took place. This has led to the creation of washout. The washout has been confirmed to be present below the casing shoe by analysis of a caliper log.
A prior attempt to access the open hole with CT was not successful. Accordingly, several Bottom Hole Assembly (BHA) designs were thoroughly examined to determine the appropriate CT deployment tool and carry out a planned acidizing work on the water injector well. The contemplated BHA designs were initially planned to include conventional well intervention tools or a combination of these tools such as knuckle joints, straight bars, and a hydraulic centralizer. However, these tools were ruled out due to their previous failure to access the wellbore in the case study well (knuckle joints and straight bars) or the risk of CT being stuck in the open hole (hydraulic centralizer).
After a careful consideration of all relevant parameters to the acidizing work, an open hole washout maneuvering technology was deployed. The CT conveyed technology consisted of a torque through knuckle joint, mechanical rotating tool and a bended sub. The deployment of this innovative technology was successful in passing the abovementioned washout. The CT successfully reached the well total depth and the benefits of this technology were fully realized as the open hole section of the reservoir was entirely exposed to the acid treatment
Tracer technology has evolved significantly over the years and is being increasingly used as one of the effective tools in the reservoir monitoring and surveillance toolbox in the oil and gas industry. Tracer surveys, conducted either as inter-well tests or single-well tests, are one of the enabling technologies that can be deployed to investigate reservoir flow performance, reservoir connectivity, residual oil saturation and reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations.
As part of the comprehensive monitoring and surveillance program for an IOR injection pilot project in a Jurassic age reservoir, an inter-well chemical test (IWCTT) was designed and implemented to investigate reservoir connectivity between injector and producer well pairs, water breakthrough times (“time of flight”), and possible inter-well fluid saturations. Four unique tracers were injected into four individual injectors, respectively, and their elution were monitored in the four “paired” up-dip producers.
In addition to the reservoir connectivity and breakthrough times between the injector and producer pairs, the results showed different trends for different areas of the reservoir. A detailed analyses of the exit age distribution and residence time distribution (RTD) curves showed two peaks for three of the injector-producer pairs and a single peak for the last pair. These were reflective of some apparent reservoir heterogeneities that were not anticipated at the beginning of the pilot.
This paper reviews the complete design and implementation of the tracer test, field operational issues, analyses, and interpretation of the tracer results. The tracer data has been very useful in understanding well interconnectivity and dynamic fluid flow in this part of the field. This has led to better reservoir description and an improved dynamic simulation model.
The use of tracers to monitor transport processes is a generic and versatile technique with a range of applications. In the subsurface domain, it has been used extensively in ground-water applications, as well as to monitor and optimize hydrocarbon reservoir production. For a general review of tracer applications in oil and gas reservoirs, see Zemel (1994). Interwell tracer applications were reviewed by Dugstad (2007).
With the increase in gas demand and the need to supply additional energy, the focus is now shifted to drilling and production activities exploiting high-pressure/high-temperature (HPHT) tight sandstone gas formations. The design optimization and selection of proper hydraulic fracturing technology is a key to succeeding in getting an economic gas production rate. Using well performance as the primary determining factor, a systematic study and evaluation was conducted on 20 vertical and horizontal wells drilled in HPHT heterogeneous sandstone reservoirs to assess effectiveness of stimulation treatments and benefits of using novel technologies. The numerous variables analyzed to determine the impact on production include different completion options, type of fracturing technology used, various proppant and fluids, fracturing method, production rate, and flowback parameters. A comprehensive database for stimulated wells was created that included reservoir parameters, completion data, minifrac and main stimulation treatment parameters (additives, fluid and proppant types, volumes, rates, and pressures), post-fracturing flowback results, and monthly production data. The production data were normalized on reservoir quality to strengthen the effect of fracturing parameters on well productivity independent of reservoir quality. Correlations were drawn using the Pearson correlation coefficient to compute the upward and downward data trends, ensure use of good quality data, and discard the few nonaligned data. Numerous very useful plots were constructed that show the different trends of the variables evaluated and how they affect production rate.
The results demonstrate the importance of proper well landing with strong influence of reservoir quality on post-fracturing production results. The channel fracturing technique offers near-infinite fracture conductivity and shows very promising results compared with conventional treatments. Pumping the bigger fracturing jobs typically yields better production results, but proppant type and schedule should be designed accounting for reservoir quality. Pad volume should be designed to achieve optimum pressure at the end of the treatment, not too high but not too low. Post-fracturing production parameters are as important for the well performance as the stimulation treatment itself. The analyses identified the key post-fracturing production drivers in the gas reservoirs and ways to improve production of future wells drilled in various formations under similar conditions.
In matrix acidizing, the aim is to create long conduits (wormholes) inside the reservoir formation which ultimately results in productivity increase. Acid in oil emulsion is used in the industry for stimulating carbonates with diesel commonly as the oil phase and hydrochloric acid (HCl) as the acid phase. Emulsifying HCl has numerous benefits over regular HCl. Perhaps the main benefit is deep penetration near the wellbore. Also, less corrosion damages are caused since the external phase is hydrocarbon (diesel). Several studies showed the success of replacing diesel as an external phase with other hydrocarbon oil, such as crude oil and xylene.
This work utilizes the extra hydrocarbon left unused –or sometimes dumped– from refineries, referred to as waste oil. The chemical composition of waste oil is studied. The HCl-waste-oil emulsion is prepared using 15 wt% HCl with a ratio of 70:30 of acid-to-oil. This paper reports results on the thermal stability and rheological properties of the HCl-waste-oil emulsion. All thermal stability experiments are conducted at a high temperature, 120 °C.
The results show that the HCl-waste-oil emulsion is a shear-thinning fluid. Power-law model is applicable seamlessly to all of the apparent viscosity data for all measured temperatures. The optimum conditions are found to be; 0.5vol% and 600 rpm for emulsifier concentration and mixing speed, respectively. Overall, the lab results show a promising potential for the HCl-waste-oil emulsion to be used in the field.
This work takes into account; reducing the budget of acidizing job along with environmental concerns. Apart from using low emulsifier concentration and low mixing speed, it makes use of the unwanted hydrocarbon from refineries.
An emulsion is a combination of two immiscible liquids: oil and water. The emulsion is prepared using a mechanical and/or a chemical means to reduce the interfacial tension between the two immiscible liquids. Mechanical means such as providing enough agitation using a blender. Chemical means such as adding special surfactants. In both scenarios the interfacial tension is reduced resulting in an emulsion. Since the emulsion is thermodynamically unstable it is bound to separate into its parent liquids. Hence, stability of the emulsion is of critical importance for well stimulation applications. Obviously, combining the mechanical and chemical means will result in a more stable emulsion. In oil and gas industry, emulsions are widely used to stimulate wells in order to increase the productivity or injectivity. Emulsions are used with acid as the water phase and diesel as the oil one. For carbonate reservoirs, diluted HCl acid is the water phase; hence, referred to as emulsified acid.
The objective of this work is to improve the efficiency of using microwave to produce heavy oil formations. Thermal technologies are proven to be the most efficient for heavy oil recovery, with steam being the most widely used technique. However, steam injection has many limitations. The use of microwave as an alternative thermal source provides in-situ heating to overcome several challenges; but heat penetration depth is a challenging area that limits its applicability. This paper presents a numerical study to explore the factors that affect heat generation and penetration depth of this microwave-assisted technique. In addition, it presents and compares four different solutions to improve its performance.
A commercially available thermal reservoir simulator is used to model the use of microwave to produce heavy oil reservoirs. In this study, a heavy oil formation gets exposed to microwave irradiations at different frequencies and power levels. Production rate, cumulative production, temperature profile around the wellbore, and penetration depth of using microwave alone and in combination with four improvement techniques are monitored and analyzed. The improvement techniques include creating a network of producers and microwave wells, cyclic microwave/production operation, combining microwave with water injection, and the use of activated carbon as a microwave enabler.
The results of this study shows that microwave frequency is the main factor that controls heat penetration depth. On the other hand, power level affects significantly the amount of generated heat. This work also shows that combining microwave with any of the proposed solutions would increase the cumulative oil production by 14 to 150%. Their performance is affected by many factors related to the targeted reservoir, heavy oil properties, and microwave specifications; however, in this paper we focus on microwave power-level, frequency, and other factors related to each of the presented techniques.
Using microwave is one of the solutions to produce heavy oil reservoirs especially if other techniques are more difficult and costly to apply. The proposed solutions improve the performance of this microwave-assisted technique and overcomes some of its major challenges. This will unlock huge heavy oil resources especially in deep and offshore reservoirs.
Transient linear triple porosity diffusion models (TPM) have been developed to justify the unexpected high gas production observed in naturally fractured, nanoporous shale gas reservoirs (NNSGR's). However, a critical assessment of the predictive capabilities of these models reveal that if the presence of obstacles, disconnected pathways in the matrix, and/or poor fracture connectivity in the fracture-matrix system are to be considered, these models may be inappropriate to describe the gas transport mechanisms in these complex systems. To overcome these limitations, an anomalous triple porosity model (ATPM) is developed to describe the gas production from a horizontal well producing in a NNSGR, allowing for the possibility of sub-diffusion in the matrix and micro-fracture within the stimulated reservoir volume (SRV).
The mathematical model entails the use of a modified constitutive flux relationship for the flow behavior in the matrix, micro and macro-fractures rather than the empirical Darcy's equation. The Laplace transform method is employed to handle the resulting mathematical model to obtain semi-analytical expressions for the dimensionless matrix pressure, micro fracture pressure, macro fracture pressure, and wellbore flowrate. Subsequently, qualitative and quantitative validation of the rate-transient at the wellbore against existing solutions in literature are demonstrated.
The ATPM solution converges to both the transient linear double porosity diffusion mathematical model (DPM) and the sequential TPM solutions established in the literature under very limiting conditions. The sensitivity of the introduced parameters was analyzed and presented through numerically generated type curves. Parametric study suggests that the derived ATPM solution exhibits unique behaviors and trends not observed in the previous mathematical models. Furthermore, the parametric study reveals the magnitude of the diffusion exponent affects the slope of the straight line observed in the log-log plot of rate and time.
The advantage of the ATPM is that detailed information of the matrix, micro fracture and macro fracture petrophysical properties can be modeled as compared to the TPM. Furthermore, this model may find wide spread application for predicting the performance of horizontal wells producing in NNSGR's where analog studies reveal low spacing aspect ratio in the reservoir.
The determination of optimum well locations and number of wells needed during green field development always comes with unprecedented challenges because of the geological uncertainty, and the non-linear relationship between the input and output variables associated with real reservoirs. These variables are key sources affecting the viability and validity of the results.
Reservoir simulation is one of the least uncertain and most reliable prediction tools for dynamic performance of any reservoir. As field development progresses, more information becomes available, enabling us to continually update and, if needed, correct the reservoir description. The simulator can then be used to perform a variety of exercises or scenarios, with the goal of optimizing field development and operation strategies. Optimizing well numbers or locations under such geological uncertainty is achieved by using a reservoir simulator under several geological realizations, and these require multiple reservoir simulations to estimate the field performance for a given well configuration at a given location.
Using reservoir simulation becomes impractical when dealing with real field cases incorporating multimillion cells because of the associated CPU demand constraints (Bouzarkouna et al., 2012). For instance, to determine the optimum well locations in a giant field that will result in the most efficient production rate scenario, one requires a large number of simulation runs for different realizations and well configurations. A large amount of runs is technically difficult to achieve even if we have access to super computers.
The Fast Marching Method (FMM), which is based on solution of Eikonal equation, can be used to find the optimum well locations in a green oil field by tracking the pressure distribution in the reservoir. The FMM will enable us to calculate the radius of investigation or pressure front as a function of time without running any simulation and with a high degree of accuracy under primary depletion conditions.
The main purpose of this paper is to study the effect of mobility on FMM and extend the investigation of its validity to include two phase-flow and convection-dominated flow and evaluate the ability of the methodology to predict the dynamic performance of the reservoir during pseudo-steady state flow regime.
Ahmed, Abdulazeem (King Fahd University of Petroleum and Minerals) | Mohamed, Mahmoud (King Fahd University of Petroleum and Minerals) | Salaheldin, Elkatatny (King Fahd University of Petroleum and Minerals) | Assad, Barri (King Fahd University of Petroleum and Minerals) | Muhammadain, Abdulrahim (King Fahd University of Petroleum and Minerals)
When carbonate in sandstone rocks exposed to seawater based acids, calcium sulfate will precipitate. Recently, chelating agents/seawater solutions were introduced to prevent scaling problem in sandstone formations. The objective of this study is to introduce DTPA (diethylene tri-amine penta-acetic acid)/ seawater solution combined with potassium carbonate as a clay stabilizer and catalyst to stimulate sandstone reservoirs.
Solubility tests of Bandera sandstone (10 % illite content) in high pH DTPA solutions diluted with seawater were performed to determine the optimum concentration of DTPA and potassium carbonate. Computed Tomography (CT) scan was conducted before and after the acidizing process to assess the performance of the new formulation. Coreflooding experiments were carried out on Bandera sandstone cores to investigate the ability of the new formulated fluid to stimulate sandstone formations. Inductively coupled plasma (ICP) was used to analyze the collected effluents to understand the mechanism of seawater and potassium carbonate effect on the reaction of DTPA with sandstone rocks.
The results showed good compatibility between DTPA seawater based fluids and Bandera sandstone cores. No precipitations were detected during the solubility tests. 20 wt. % DTPA at pH of 11 combined with 3 wt. % potassium carbonate gave the optimum solubility ratio. Reduction in CT-number in the treated sandstone cores indicates the porosity enhancement after treatment. Permeability measurements showed about 40 % increase in permeability improvement ratio of Bandera sandstone cores after injecting 6 pore volumes of 20 wt. % DTPA at pH of 11 diluted using seawater combined with 3 wt. % of the catalyst at 250°F and the injection rate was 5 cm3/min.
The obtained results of this work will enrich the outcome of sandstone acidizing using seawater based fluids without calcium sulfate precipitation in offshore operations at high temperature and also will prevent the problems associated with high illite content formations.
Offshore stimulation jobs are expensive operations due to the cost of transporting fresh water to the offshore platforms. Generally, engineers use fresh water to formulate acids to make stable solutions that can effectively enhance formation permeability without any further problems. Seawater was introduced to prepare and flush acids to minimize the cost of logistic supply of the fresh water. However, seawater has the problem of scale precipitation. Sulfate ions from seawater combine with calcium, barium, or strontium ions in the formation brine or with calcium in the spent acid to produce sulfate scale. He et al. (2011) found out that calcium sulfate precipitated at different stages of the acidizing process after using HCl prepared using seawater. Oddo et al. (1991) reported the same phenomena when seawater and KCl were used to post flush the mud acid from offshore wells after treatment. So to come up with cost effective seawater based acid for sandstone acidizing we have to consider many factors. At first, main acid should be compatible with seawater to have proper solution without precipitations. Furthermore, this formulation should be able to remove the damage, improve the permeability and maintain sandstone formation stability.
Polymer flooding has been widely applied in China and can enhance oil recovery by more than 10%. However, there is about 50% remaining oil in reservoirs. Therefore, it is important to develop a new technology which based on the mechanism of both lowering interfacial tension to an ultra-low value (10-3 mN/m grade) and improving sweep efficiency of displacing fluid after polymer flooding in extremely heterogeneous reservoirs. A novel dispersed viscoelastic microsphere flooding system (DVMFS) by the combination of low elastic microspheres, surfactants and polymers is suggested. Firstly, the suspension stability of the DVMFS was studied using TSI value measured by stability analyzer. The influence of surfactant concentration, polymer concentration and reservoir temperature was conducted. Then, the ability to reduce interfacial tension was measured using interfacial tensionmeter. Furthermore, conformance control ability was evaluated by double tube parallel model. Oil displacement efficiency of the system was obtained through core flooding experiments under a given reservoir condition after polymer-flooding. The results show that the low elastic microspheres with 23.6 Pa used in this paper has great swelling capability at the reservoir condition of Gangxi Oilfield. The deformable microsphere passes throw the pore throat easily because of its low elasticity. The dispersed system has great suspension stability. The lower the temperature and the higher concentration of surfactant and polymer are, the smaller the TSI value and the better the suspension stability are. Besides, the system has an ultra-low oil-water interfacial tension. The results of double tube parallel model and oil displacement experiment indicate that the injection profile was significantly adjusted and the oil recovery efficiency was increased by 21.66% after polymer flooding. This conformance control is a dynamic one because of the combination of low elastic microsphere, surfactant and polymer, which is different from the common gel conformance control technology. The DVMFS displays a promising application to improve oil recovery after polymer flooding for extremely heterogeneous reservoirs.