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Hydraulic fracturing is the most common stimulation technique to make hydrocarbon production feasible and optimal worldwide. However, it has been preferentially focused on low permeability formations, and when applied to high permeability, it has been focused on sand control. This article outlines the process and results of the hydraulic fracturing campaign for productivity purposes (not for sand control) in the basin of the eastern plains of Colombia given the petrophysical characteristics of the cretaceous formations, where thinking "out of the box" and separating from the existing premises, resulted in successful implementation of this technique in high permeability wells (~ 1D), high water cuts (up to 80% BSW) and heavy oil reservoirs (9–12 API). The technical process consisted on several steps leading to the success of the campaign, which included: Formation damage study that identified candidate wells and damage mechanisms affecting them.Refining of the petrophysical model from pressure testing to establish incremental production.Adjustment of fracture models using varying anisotropy from special sonic log runs.Using state of the art technologies such as mobility enhancers and Flow back proppant additives as active ingredients of the fracturing fluid. This article presents the outcomes of more than 40 wells intervened to date with an average volumetric increment of ~ 250 BOPD per well, consistent reductions of BSW up to 60% and optimized operations which let the operator consider the hydraulic fracturing as a production optimization option for the field under analysis.

Sour gas is being produced from a number of carbon-steel-completed wells in the US (Mississippi, Alabama), Canada, France and Saudi Arabia. The gas stream contains various levels of hydrogen sulfide, carbon dioxide and is produced from high temperature reservoirs (with temperatures ranging from 160 to 410°F). The combination of hydrogen sulfide with high temperatures introduces challenges related to corrosion and iron sulfide (FeS) scale formation. The thermodynamics and kinetics of iron sulfide formation will be reviewed. There is a large literature on the thermodynamics and kinetics of iron sulfide scales in the context of corrosion of mild steel. High temperatures and high concentration of hydrogen sulfide favor the formation of pyrrhotite and trolite which are an order of magnitude less soluble than cubic FeS or mackinawite. Saudi Aramco has been producing sour gas from deep carbonate reservoirs since 1984. The mole percentage of hydrogen sulfide (H 2 S) in the gas of these wells range from 1 to 23, while the mole percentage of carbon dioxide in the gas range from 3.7 to 8. Bottomhole temperatures vary from 265 to 320°F. Corrosion inhibition treatment has been sporadic. Chemical and mechanical methods of scale removal have been used in different wells. In a specific instance, the amount of scale has been measured from a given well and the composition has been noted as a function of depth. Assessment about the amount of scale and the potential sources of iron will be provided. Thermodynamic studies of iron sulfide scales will also be reported to explain some of the field observations. The paper provides a summary of the current fundamental understanding in iron sulfide scale (FeS) and corrosion kinetics. It reveals that many oilfield operators do have special stimulation procedures for these wells. These include: special acid stimulation packages, well pickling and processes for continuous injection of corrosion inhibitors to mitigate the iron sulfide scale problems. Results and analysis concerning corrosion and scale problems for specific wells in deep hot gas wells will be presented. The paper will provide a reference point for iron sulfide scale problems in high temperature sour gas wells and for future development in the area.

Scale formation has been a persistent challenge in many sour gas wells producing from one of the world's largest gas reservoir in Saudi Arabia. Accumulation of scale deposits on downhole tubular and in wellhead manifold interferes field operation, limits well accessibility and decreases well productivity. Extensive efforts have been devoted to understand the scale formation process and to develop cost-effective mitigation strategy. This paper discusses the up-to-date knowledge on the scale formation in these prolific gas wells and presents the descaling technologies deployed and currently considered.Scale composition analyses have been performed for a large number of deposits collected during well workovers and interventions. Wide range of mineral phases were identified and their distribution showed significant variations with samples. Scale often consisted of several different mineral phases. Iron sulfides were usually the dominant components, these included pyrrhotite, troilite, mackinawite, pyrite, marcasite and greigite. Ferric iron scales, such as hematite, magnetite, akaganeite, goethite and lepidocrocite, were also common in the scale mixtures. Common mineral scales, especially calcite, were often found. In addition, iron carbonate and other ferrous iron compounds were also identified. The relative abundance of these minerals showed wide-ranging variations from well to wells. Those variations also changed and with depth and time in the given wells. A more interesting phenomenon was the layered structure in the scale deposits, with two distinct layers having very different compositions. These results provided critical information for the understanding of scaling formation process.Scale removal with chemical method had limited success in past. Scale dissolvers, based on HCl acid, caused severe tubular corrosion and formation damage. Different mechanical techniques have been tested and implemented over the years. These field experiences are reviewed in the paper. Also, challenges and requirements for scale dissolvers are discussed.

The carbonate gas producing zones of the Ghawar field have been impacted by extensive FeS scale deposition, reducing overall gas production and significantly increasing risks of well interventions. Previous remediation included the use of workover rigs, which can be costly because of the time necessary for workovers and lost production. H 2 S levels (2 to 5%) found in the reservoir also contribute to higher costs and risks when using workover rigs.A chemical solution was also considered, but the FeS could not be 100% dissolved with HCl and the chemical reaction generated large amounts of H 2 S in addition to existing high levels of H 2 S in the reservoir. This poses a safety concern with the returns at surface along with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT.This paper discusses two wells where mechanical descaling was applied using CT. Each well involved four major challenges that included low reservoir pressure, increased reservoir temperature, horizontal openhole completion, and scale with high specific gravity (3.7 to 4.3). The low reservoir pressure required pay zone isolation to allow for returns to circulate out the heavy scale and to minimize fluid losses to the formation. The fact that the wells had long, openhole sections created another challenge for isolation and cleanout. With a bottomhole temperature (BHT) as high as to 310°F, the operational envelope of temporary chemical packers in combination with loss circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge discussed in this paper is the process to clean out the LCM in the horizontal openhole and bring the well back to maximum gas production using pinpoint stimulation techniques.

For the past decade, Saudi Aramco has been successfully exploiting tight gas sandstone formations. These formations are routinely hydraulically fractured to enhance gas production, but as the development of the existing fields continues into deeper formations the exploration of new reservoirs emerges. New challenges are now being faced especially, considering that higher temperature is being encountered and the fracture fluids currently being used (based on borate crosslinker) are not stable enough to tackle the extreme conditions. Metal-crosslinked fracture fluids have long been the most popular class of high viscosity fracturing fluids. Primary fluids that are widely used are titanate and zirconate complexes of guar, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), or carboxymethyl hydroxyethyl cellulose (CMHEC). Zirconium-delayed CMHPG are typically used for high temperature applications. These types of fluids provide high temperature stability with low polymer loading with the added benefit of salt compatibility. The proppant transport capabilities of the metal-crosslinked fluids are excellent. Zirconiumdelayed CMHPG fracture fluid is currently the preferred fluids due to its extraordinary stable characteristics for bottom-hole temperatures (BHTs) up to 375°F. This paper addresses the research, lab testing and successful application of a metal-crosslinked fluid used for fracturing operations of a high temperature (312 ~330 °F) tight gas reservoir in Saudi Arabia, with its post-treatment evaluation to optimally develop these reservoirs in harsh bottom-hole conditions.

Tight gas refers to natural gas reservoirs that have very low porosities and permeabilities. Most of the tight-gas reservoirs presently being developed are sandstone formations, although carbonate rocks can also be tight-gas producers. The standard industry definition for a tight-gas reservoir is a rock with matrix porosity of 10% or less and permeability of 0.1 millidarcy or less, exclusive of natural fracture permeability. Unconventional gas resources, including tight sands, constitute some of the largest components of remaining natural gas resources in the Middle East and North Africa. Developing unconventional and tight-gas reservoirs will allow Saudi Arabia to better meet rising domestic energy needs.During the past decade, conventional formations were stimulated successfully in Saudi Arabia using conventional completion techniques. However, as the development of existing fields continues into deeper formations and the exploration of new reservoirs is mainly toward unconventional reservoirs, new challenges are now faced, especially considering that lower permeabilities, higher stresses, and higher temperatures are experienced. An evaluation of the current techniques is necessarily in order to overcome the challenges in these extreme conditions. This paper reviews the successful application of specific completion techniques and technologies being implemented in the development of tight-gas reservoirs currently being exploited in Saudi Arabia.

In this paper a review of the thermodynamics of gas/condensate and water systems with hydrogen sulfide and water/hydrocarbon wetting and its influence on corrosion is presented.Compositional analysis is used to provide information on the variation of different material streams and composition as a function of depth. Although on the surface, the liquid stream of a well can predominately consists of hydrocarbon, the liquid stream downhole can have a very different composition. The variation of liquid composition, pressure, temperature, ionic composition and flow regime can have interesting implications on sour corrosion and scale formation.Calculations on scaling conditions and thermodynamic conditions that cause corrosion are done on a well under bottom hole and well head conditions. Iron sulfide films that are formed during high temperature CO 2 /H 2 S corrosion of carbon steel and often layered structures of scale are formed where the composition of scale varies with depth. The calculations provide guidance on the types of iron sulfide and iron oxyhydride scales that may form.