Alkandari, Dana K. (Australian College of Kuwait) | AlTheferi, Ghaneima M. (Australian College of Kuwait) | Almutawaa, Hawra'a M. (Australian College of Kuwait) | Almutairi, Maryam (Australian College of Kuwait) | Alhindi, Nora (Australian College of Kuwait) | Al-Rashid, Sherifa M. (Australian College of Kuwait) | Al-Bazzaz, Waleed H. A. (Kuwait Institute For Scientific Research)
Formation damage is the impairment of permeability of rocks inside a petroleum reservoir. This occurs during drilling, production, stimulation and enhanced oil recovery operations, by various mechanisms such as chemical, mechanical, biological and thermal. Near wellbore formation damages have a great impact on productivity of the damaged formation. Acidizing is a stimulation method to remove the effect of near wellbore damage through reacting with damaging materials or the formation rocks (carbonate or sandstone rocks) to restore or improve permeability around the wellbore. Several experiments are conducted to study the effect of temperature and acid concentration combined on the efficiency of matrix acidizing. Three different concentrations scenarios of hydrochloric acid (3%, 15%, and 28%) and 4 different temperatures scenarios (25 °C, 35 °C, 70 °C, and 100 °C) were tested to investigate pore-enlargement success effect on permeability. The purpose of this experiment is to introduce the concept of optimized temperature augmented with optimized acid concentration in carbonate matrix acidulation. Morphology of pore geometry and area measurement software is used. New Advancement in imaging that captured pore area enlargement as big-data necessarily for artificial intelligence modeling. Captured pores before treatment and captured pores after thermal-HCL acid treatment have demonstrated that image processing of the actual acidized rock data can select the optimized recipe concentration of acid that will increase permeability, hence recovery. The results show that matrix acidizing is an effective method to improve permeability and enhance production, as it demonstrates that using less acid concentration with the optimized temperature can result in a favorable and satisfying outcomes.
Creating sufficient and sustained fracture conductivity contributes directly to the success of acid-fracturing treatments. The permeability and mineralogy distributions of formation rocks play significant roles in creating nonuniformly etched surfaces that can withstand high closure stress. Previous studies showed that, depending on the properties of formation rock and acidizing conditions (acid selection, formation temperature, injection rate, and contact time), a wide range of etching patterns (roughness, uniform, channeling) could be created that can dictate the resultant fracture conductivity. Insoluble minerals and their distribution can completely change the outcomes of acid-fracturing treatments. However, most experimental studies use homogeneous rock samples such as Indiana limestone that do not represent the highly heterogeneous features of carbonate rocks. This work studies the effect of heterogeneity and, more importantly, the distribution of insoluble rock on acid-fracture conductivity.
In this research, we conducted acid-fracturing experiments using both homogeneous Indiana limestone samples and heterogeneous carbonate rock samples. The Indiana limestone tests served as a baseline. The highly heterogeneous carbonate rock samples contain several types of insoluble minerals such as quartz and various types of clays along sealed natural fractures. These minerals are distributed in the form of streaks correlated against the flow direction, or as smaller nodules. After acidizing the rock samples, these minerals acted as pillars that significantly reduced conductivity-decline rate at high closure stresses. Both X-ray diffraction (XRD) and X-ray fluorescence (XRF) tests were performed to pinpoint the type and location of different minerals on the fracture surfaces. A surface profilometer was also used to correlate conductivity as a function of mineralogy distribution by comparing the surface scans from after the acidizing test to the scans after the conductivity test. Theoretical models considering geostatistical correlation parameters were used to match and understand the experimental results.
Results of our study showed that insoluble minerals with higher-strength mechanical properties were not crushed at high-closure stress, resulting in a less-steep conductivity decline with an increasing closure stress. If the acid etching creates enough conductivity, the rock sample can sustain a higher closure stress with a much lower decline rate compared with Indiana limestone samples. Fracture surfaces with insoluble mineral streaks correlated against the flow direction offer the benefit of being able to maintain conductivity at high closure stress, but not necessarily high initial conductivity. Using a fracture-conductivity model with correlation length, we matched the fracture-conductivity behavior for the heterogeneous samples. Fracture surfaces with mineral streaks correlated with the flow direction could increase acid-fracturing conductivity significantly as compared to the case when the streak is correlated against the flow direction.
The results of the study show that fracture conductivity can be optimized by taking advantage of the distribution of insoluble minerals along the fracture surface and demonstrate important considerations to make the acid-fracturing treatment successful.
Abdelfatah, Elsayed (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Wahid-Pedro, Farihah (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Melnic, Alexander (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Vandenberg, Celine (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Luscombe, Aidan (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Berton, Paula (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Bryant, Steven (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada)
Waterflooding of heavy oil reservoirs is commonly used to enhance their productivity. However, preferential pathways are quickly developed in the reservoir due to the significant difference in viscosity between water and heavy oil, and hence, the oil is trapped. Here, we propose a platform for designing ultra-low IFT solutions for reducing the capillary pressure and mobilizing the heavy oil.
In this study, mixtures of organic acids and bases were formulated. Three different formulations were tested: (i) Ionic liquid (IL) formulation where bulk acid (4-dodecylbenzene sulfonic acid) and base (Tetra-
The IL and ABs formulation are acidic solutions with pH around 3. The ASBs formulation is highly basic with a pH around 12. Non of the formulations salted out below 14 wt% of NaCl. While conventional surfactant, SDBS, precipitated at salt concnetration less than 2 wt% of NaCl. The formulation solutions (1 wt%) have different optimum salinities: 2.5 wt% NaCl for ASBs, 3 wt% NaCl for IL and AB. Although IL and AB have the same composition and molar ratio of the components, their performances are completely different, indicating different intermolecular interactions in both formulations. Corefloods were conducted using sandpack saturated with Luseland heavy oil (~15000 cP) and at fixed Darcy velocity of 12 ft/day. A slug of 1 PV of each formulation was injected after waterflooding for 5 PV and followed by 5 PV post-waterflooding. In the hydrophilic sandpacks, IL and AB formulation produced an oil bank, consisting mainly of W/O emulsion, with oil recovery that is 1.7 times what was recovered by 11 PV of waterflooding solely. Majority of the oil was recovered in the 2 PV of waterflood following the IL slug. ASBs formulations produced O/W emulsions with prolonged recovery over 5 PV waterflooding after the ASB slug. The recovery factor for ASBs was 1.6 times that recovered for 11 PV of waterflooding only. In the hydrophobic sandpacks, The ASB formulation slightly increased the recovery factor compared to only waterflooding. While for IL and AB formulation, the recovery factor decreased.
This work presented a novel platform for tuning the recovery factor and the timescale of recovery of heavy oil with a variable emulsion type from O/W to W/O depending on the intermolecular interactions in the system. The results demonstrate that the designed low IFT solutions can effectively reduce the capillary force and are attractive for field application.
Acid-tunneling is an acid jetting method for stimulating carbonate reservoirs. Several case histories from around the world were presented in the past showing optimistic post-stimulation production increases in open-hole wells, comparing to conventional coiled tubing (CT) acid jetting, matrix acidizing, and acid fracturing. However, many questions about the actual tunnel creation and tunneling efficiency are still not answered. In this paper, the results of an innovative full-scale research program involving water and acid jetting are reported for the first time.
The tunnels are constructed through chemical reaction and mechanical erosion by pumping hydrochloric (HCl) acid through conventional CT and a bottom-hole assembly (BHA) with jetting nozzles and two pressure-activated bending joints that control the tunnel initiation directions. If the jetting speed is too high and the acid is not consumed in front of the BHA during the main tunneling process, then unspent acid flows toward the back of the BHA and creates main wellbore and tunnel enlargement with potential wormholes as fluid leaks off, lowering the tunneling length efficiency.
Full-scale water and acid jetting tests were performed on Indiana limestone cores with 2-4 mD permeability and 12-14% porosity. Many field-realistic combinations of nozzle sizes, jetting speeds, and back pressures were included in the testing program. The cores were 3.75-in. in diameter by 6-in. in length for the water tests, and 12-in. in diameter by 18-in. in length for the tests with 15-wt% HCl acid. The jetting BHA was moved as the tunnels were constructed, at constant force on the nozzle mole, to minimize the nozzle stand-off distance. Six acid tests were performed at the ambient temperature of 46F and two at 97F. The results from the acid tests show that the acid tunneling efficiency can be optimized by reducing the nozzle size and pump rate. The results from the water and acid tests with exactly the same parameters to match the actual CT operations in the field show that the tunnels are constructed mostly by chemical reaction and not by mechanical erosion. The acid tunneling efficiencies obtained from the full-scale acid tests are superior to the average tunneling efficiency of more than 500 actual tunnels constructed during more than 100 acid tunneling operations performed to date worldwide.
The paper describes the full-scale water and acid jetting tests on Indiana limestone cores. The major novelty of this test program consists of performing all measurements with back pressure, unlike all previous water and acid jetting studies reported in literature, to more accurately mimic the downhole well conditions. The novel understanding of the combined effect of the nozzle size, pump rate, and back pressure significantly improves the actual acid-tunneling efficiency.
Numerous carbonate reservoir discoveries were made in Indonesia (
The process involves multiple cycles—from formation evaluation (e.g., geomechanics analysis, design of an effective fracturing method, and production forecasting) through the economic impact to the operator. During the early phase of this integrated study, the uncertainties of all static and dynamic parameters (i.e., geological complexity, rock physics, and stress profile) were considered for fracturing design. Production performances from multiple fracturing stimulation scenarios were then modeled and compared to select the plan that optimizes production for the Berai Formation.
Results demonstrated an effective multidiscipline approach toward a comprehensive strategy to meet the ultimate objective in optimizing production. This project leveraged formation evaluation and fracturing design to deliver integrated solutions from exploration to accurate production forecast. The well stimulations were performed by carefully selecting fluid characteristics based on geological-petrophysical properties, pressure, and stress profiles within the area. Results yielded excellent production gains—for the best case, up to 50% with an average of 40% in comparison with initial production by using an acid that provides optimum fracture geometry and permeability.
This opportunity demonstrated the importance of understanding formation behavior and the parameters that aid the selection of an appropriate fracturing design for a low porosity/permeability carbonate reservoir.
Recently two multilateral horizontal wells have been completed offshore using dedicated multistage hydraulic fracturing completions. The first well, located in the Central North Sea (referred to as ML-CNS), was stimulated using acid fracturing; while the second well, located in the Black Sea (referred to as ML-BKS), was stimulated using proppant fracturing. This paper presents the different drivers, challenges and lessons learned for each well while emphasizing the well construction and stimulation methodologies developed for the different reservoirs and field characteristics.
The field development drivers for drilling and completing these offshore hydraulic fractured multilateral wells, a first of their kind globally, was different for each case. The objective of the first project, initially considered uneconomic, was to engineer a technical solution for completion and production of two separate reservoirs with only one subsea well. The second project was seeking to optimize infill drilling from the last available slot on the offshore platform to maximize reservoir contact and production in the same reservoir. ML-CNS was a TAML Level 2 completion with a 14-stage, 5 ½" multistage completion run in each lateral and set-up for sequential acid fracturing. Operationally, the first lateral was drilled and stimulated, followed by the drilling and stimulation of the second lateral, using the drilling whipstock to navigate through the multilateral junction. ML-BKS was a TAML Level 3 completion that had a 6-stage, 4 ½" multistage completion installed in each lateral, which were proppant fractured following a sequence designed to minimize the jack-up rig time required. Both legs were drilled and completed prior to starting the stimulation, access to either lateral was achieved with the existing workover unit on the platform by manipulating a custom designed BHA.
The lessons learned from the first project executed in the North Sea were able to be transferred and applied to the second project in the Black Sea to allow for a more efficient and confident completion solution. Led by varying economical and regional constraints, the key factor for both wells centered on delivering operationally simple and reliable multilateral completion designs to economically meet the field development strategy in place.
To the knowledge of the authors and following subsequent literature research, both wells are a worldwide first for an offshore multilateral well completed with multistage acid fracturing and multistage proppant fracturing, and together they represent a new trend in cost-effective offshore field development through well stimulation. The successful case studies for both wells with the combined analysis of the benefits, challenges, and lessons learned will provide a guide and instill confidence with operators who find this approach beneficial with a view to applying it in other assets.
Alabi, Oluwarotimi (RAB Microfluidics R&D Company Limited) | Wilson, Robert (RAB Microfluidics R&D Company Limited) | Adegbotolu, Urenna (RAB Microfluidics R&D Company Limited) | Kudehinbu, Surakat (RAB Microfluidics R&D Company Limited) | Bowden, Stephen (University of Aberdeen)
Oil condition monitoring for rotating and reciprocating equipment has typically been laboratory based. A technician or engineer collects a sample of lubricating oil and sends this to a laboratory for chemical analysis. After the laboratory has performed the analysis the results are sent to the engineer to make decisions on the health and/or condition of the machinery. This process can take up to 6 weeks, and consequently analysis may end up being performed only quarterly with little likelihood of critical failures being pre-empted. The slowness of oil condition monitoring analyses performed in laboratories has led engineers to substitute for real-time monitoring methods such as vibration analysis and thermography. Nevertheless, the chemical composition of the lubricating oil remains the gold standard for the diagnosis of machine health. The automation of methods for analysing the chemical composition of lubricating oil in real-time would provide engineers with data on the immediate condition of a particular piece of machinery, allowing the early diagnosis of incipient faults.
In this paper, we present a microfluidic technique that can perform real-time continuous monitoring of the chemical composition of lubricating fluid from rotating and reciprocating equipment. Results from this technique both in laboratory and field environments are comparable to conventional laboratory measurements. The microfluidic technique exploits the flow of fluids within micrometre-dimensioned channel, permitting liquid-liquid diffusive separation between otherwise miscible non-aqueous fluids. It can be shown that several fluids e.g. methanol, hexane etc. can selectively extract target components in lubricating oil. Following an extraction, these components can be quantified using a combination of optical techniques, e.g. UV/Vis, Infrared etc. This microfluidic technique has been demonstrated for a range of lubricating oils with several acid, alkaline detergent, asphaltene/insoluble content. This technology can potentially revolutionise the way oil analysis is carried out, automating and making the process rapid and in real-time.
This paper presents a newly designed triaxial fracturing system and describes a series of experiments that verified the validity of tool-free chemical diversion for multistage fracturing of openhole horizontal wells. The case history presented in the complete paper describes the performance of an acid-fracturing intervention in an HP/HT well in which this intervention was the last procedure considered to evaluate the productivity of a Marrat Formation well.
The fourth industrial revolution is taking the oil and gas business by storm. Many companies have increased resources for big-data analytics and machine learning. Though no one sees physical oilfield services as in decline, development in these areas may take a back seat to artificial intelligence. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. This paper describes interpretation results of a 4D seismic-monitoring program in a challenging Middle East carbonate reservoir.
Berry, Sandra L. (Baker Hughes, a GE Company) | Palm, Dustin C. (Baker Hughes, a GE Company) | Usie, Marty J. (Baker Hughes, a GE Company) | Schutz, Ronald W. (TiCorr LLC) | Walker, Heath W. (Arconic Energy Systems)
Matrix acidizing treatments containing hydrogen fluoride (HF) acid have been utilized in stimulation treatments of offshore wells to remove skin associated with fines migration for many years. In the last few years, operators have moved toward the use of organic acid - HF acid treatments due to corrosion concerns in the downhole tubular strings during the initial pumping of live acid and in the Titanium Stress Joints (TSJ) during the acid flow back through the production riser. A corrosion inhibitor to inhibit any unspent HF in the acid flowback returns would be beneficial to operators. Production of spent acid flowing back through the production riser is seriously being considered because significant cost savings may be realized over other acid flowback options. However, although most HF acid systems are mostly and/or highly spent during the reaction time with the formation mineralogy, even small concentrations of remaining free HF in the spent acid returns can result in severe bore surface corrosion (etching) and byproduct hydrogen absorption by the riser system TSJ. Lab studies were performed with several different inhibitor formulations added to two different spent organic - HF acid fluid systems to determine the ability for these candidate inhibitors to thwart corrosion (etching) and corresponding hydrogen uptake on ASTM Grade 29 titanium (Ti-29) test coupons. These candidate inhibitors were subjected to four-hour exposure tests conducted at 170 F under 3500 psi pressure with various inhibitor concentrations to determine if the package could meet screening criteria of corrosion/etch rate of less than 0.5 mils per day (0.5 thousandths of an inch) and hydrogen uptake limits consistent with ASTM product specification limits for the short term exposure (i.e., four hours). These lab test results are compared to those from recent published lab test studies on titanium in live and spent HF containing acid fluids, along with discussion on practical implications and considerations for their field use. Developing a corrosion inhibitor to inhibit the residual HF acid in the spent flowback returns and prevent etching and hydrogen uptake by the TSJ in the production risers not only yields effective protection of the TSJ, allowing flowback fluids to be returned thru the production riser, but also offers a significant operational cost savings.