Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico

Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.

Stimulation Workflow Applied on LAPA Pre-Salt Carbonate Field Deep-Water Brazil

Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability. The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations. The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available "on call" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project. This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.

Phase transitions in natural C-O-H-N-S fluid inclusions - implications for gas mixtures and the behavior of solid H2S at low temperatures

C–O–H–N–S-bearing fluids are known as one of the most challenging geochemical systems due to scarcity of available experimental data. H2S-rich fluid systems were recognized in a wide array of world-class mineral deposits and hydrocarbon reservoirs. Here we report on a nature of low-temperature (T ≥ −192 °C) phase transitions observed in natural CH4–H2S–CO2–N2–H2O fluid inclusions, which are modeled as closed thermodynamic systems and thus serve as natural micro-laboratories representative of the C–O–H–N–S system. For the first time, we document solid–solid H2S (α ↔ β ↔ γ) transitions, complex clathrates and structural transformations of solid state H2S in natural inclusion gas mixtures. The new data on Raman spectroscopic features and a complete sequence of phase transition temperatures in the gas mixtures contribute to scientific advancements in fluid geochemistry. Enhanced understanding of the phase equilibria in the C–O–H–N–S system is a prerequisite for conscientious estimation of P-T-V-X properties, necessary to model the geologic evolution of hydrocarbon and mineral systems. Our findings are a driver for the future research expeditions to extraterrestrial H2S-rich planetary systems owing to their low temperature environments.

The formation of (Ni-Co-Sb)-Ag-As ore shoots in hydrothermal galena-sphalerite-fluorite veins

Unusual hydrothermal native As-sulfide ± native Ag ± arsenide ± antimonide ± sulfosalt ore shoots and their co-genetic sulfide-fluorite-barite-quartz host veins, which are common in the region and in whole Central Europe, were investigated at three localities in the Schwarzwald, SW Germany, to understand the physico-chemical processes governing the change from a normal (= common) hydrothermal to an exceptional ore shoot regime. Based on fluid inclusions, the formation of the gangue minerals is the result of binary mixing between a NaCl-rich brine and a CaCl2-rich brine (both ~ 20 wt% NaCl aq.). This mixing correlation, major and minor fluid composition, formation temperature (~ 150 °C), and δ34S signature are identical (within error) in ore shoots and host veins. Thermodynamic modeling indicates that ore shoot formation must have resulted from a change in redox conditions by a local influx of a volumetrically minor reducing agent, probably hydrocarbons. The elemental content and the mineralogy of each ore shoot locality (Ag-As-rich: Münstertal; Ag–Ni-As-rich: Urberg; Ag–Ni-As-Sb-rich: Wieden) reflect the metal content of the binary mixed fluid, while mineral textures, successions, and assemblages are thermodynamically and, regarding sulfur, kinetically controlled. The formation of vein and ore shoot sulfides requires an addition of sulfide, most probably from the sulfide-bearing host rocks, because thermodynamic and kinetic reasons suggest that the two major vein-forming and metal-bearing fluids are not the source of the sulfur. The final ore shoot textures are influenced by later hydrothermal remobilization processes of As and Ag. This results in a number of sulfosalts, mostly proustite-pyrargyrite. Interestingly, the greater thermodynamic stability of Sb-endmember sulfosalts enables them to form even in As-dominated fluid systems.