The Carbonate Field, one of the world's largest oil and gas fields, consists of different reservoirs with different lithology where reservoir temperature ranges from 280 °F to 330 °F. Several high temperature, high pressure (HTHP) wells were hydraulically fractured in "Reservoir A," a gas bearing formation, in the Carbonate Field in Saudi Arabia. High temperature reservoirs present a challenge to successfully fracture because a novel fracturing fluid is necessary to sustain the high temperature. Reservoir A is a sandstone gas-bearing reservoir associated with liquid condensate that in most cases requires hydraulic fracturing to enhance productivity and control sand production. Its high temperature and pressure creates technical and operational challenges. The harsh formation environment requires a prolonged fluid stability to ensure stimulation effectiveness. Once the bottom-hole static temperature (BHST) is above 300 °F, borate-based crosslinked fracturing fluid can become unstable causing a rapid viscosity loss and eventually a poor proppant carrying capacity. Metal-crosslinked fracturing fluids are well-known for high viscosity. Zirconates and Titanates are the main metal complexes of guar polymers. CarboxyMethylHydroxyPropyl Guar (CMHPG) crosslinked with Zirconium crosslinker is the most common fluid used in elevated bottom-hole applications as they develop excellent viscosity and proppant carrying capacity in these high temperature and pressure environments. Zirconate crosslinked fluids have been successfully pumped in wells where bottom-hole temperature exceeded 400 °F and resulted in a significant production increase (Stolyarov and Dean, 2011). The technical stimulation approach in Reservoir A is to induce a wide and very conductive fracture to mitigate the pressure drop the producing fluid experiences as it reaches wellbore to prevent condensate banking. It is a vital to have a stable fluid to generate the right width to accept the higher proppant concentration. This paper includes laboratory testing evaluation of fracturing fluid stability and breaker optimization. It will also show how the pressure falloff analysis was performed prior to the main frac to calibrate the fluid efficiency in the frac model and optimize fracture geometry. Post-treatment net pressure matching was conducted to predict the final fracture geometry and then nodal analysis was performed using the created fracture geometry and actual flowback data to further validate the incremental production increase after the treatment.

This paper presents a case study that describe the precipitation behavior of asphaltene and petroleum reservoir fluid. It includes a CO2 flooding process in a synthetic reservoir using CMG/GEM, ECLIPSE, and UTCOMP simulators. Solid model is used in UTCOMP, CMG/GEM and ECLIPSE simulators for asphaltene precipitation prediction. WinProp (a PVT utility from CMG/GEM) is used to generate the data for all simulators. Different cases are run to investigate the production rates resulted from different simulators (UTCOMP, CMG/GEM, and ECLIPSE) during the waterflooding period with CO2 (WAG), with and without considering the asphaltene option.

One of the main used completion techniques in the gas wells Plug and Perf for proppant or acid stimulation, where the flow through frac plugs are commonly installed to provide isolation between the planned stages to be stimulated. Once the stimulation is completed, the well is flowed back where gas is produced thru the internal diameter restriction in those frac plugs, then all plugs are milled to clear any downhole restriction. The objective of this paper is to evaluate the need of milling frac plugs by simulating the behavior of the Production Index affected by downhole restriction in frac plugs considering those are not milled. The proposed evaluation will investigate the real need of milling the flow thru plugs in the well after the frac operations, as the milling operation has a high cost and complexity. The preferred method is to flow the well without milling operation. However, if the effect of the plugs was significant on the productivity of the wells throughout the years, there will be a need to perform milling operation on the wells to ensure full wellbore accessibility. On the other hand, if the effect was not significant on the future production, the flow thru plugs can be left in the well downhole to avoid the milling operation complications. It is worth to note that milling multiple plugs in a well is a very lengthy and extremely expensive operation looking at the CT and Sand Management System (SMS) daily charges as well as the highly nitrogen consumption (Nunez et al. 2021). The analysis in this paper is split in two parts, where initially Well-A is simulated in PROSPER to compare the production performance in a Plug and Perf completed well with plugs installed or milled. Second part of the analysis is to compare 2 offset wells with real-time data: Well-X with flow thru plugs and Well-Y with flow thru plugs being milled. The results of these analysis as well as the operation total cost and complexity will help in identifying most economical way to apply.

Nowadays tight oil and gas reservoirs all around the world are increasingly exploited using wells where hydraulic fracturing is an essential technique to enable commercial productivity. In the case of a low permeability sandstone gas reservoir, understanding geological environment and selection of the optimal hydraulic fracturing design and implementation is key to obtain sustainable flow rates. Analysis of performed frac jobs and well performance across one field with 6 gas offset wells is reviewed in this paper. Wells analyzed in this paper were all drilled into a shaly sandstone reservoir, with a high probability of including a favorable net-to-gross ratio of reservoir quality sandstones. The reservoir properties of these sandstone formations vary from a well to another with an average reservoir pressure of 5,500 psi – 8,500 psi, average reservoir temperature of 300 deg F, average reservoir porosity of 6-10% and average permeability between 0.5 – 4 mD. These reservoir properties are indication of tight reservoir where hydraulic fracturing is an essential technique to enable commercial productivity from the wells as well as controlling proppant and sands flowback. In most cases, 20/40 HSP and 20/40 RC-HSP proppant types were used in frac operations to provide the required conductivity in the reservoir and also control the proppant and sand from being flowed back to the surface. In addition to the proppant type, high final proppant concentration was also one of the key parameters to ensure proppant packing is achieved at the end of the job and help minimizing proppant flow back. High level analysis of the wells production histories across the field will help to determine main factors affecting the well performance.