The wells in an oil field in East Venezuela have a bottomhole static temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in these wells. Currently, various formulations of mud acids, organics acids, and solvents are used to treat these wells with mixed results. A novel chemical system has been developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms, the new sandstone acidizing systemreduces the multiple stages in traditional sandstone acidizing to one stage;minimizes precipitations by delayed and stabilized reaction mechanisms;provides homogeneous dissolution of formation;has a much lower emulsion and sludge tendency than conventional fluids as well as lower corrosion rate; andstimulates sandstone reservoirs at high temperature by effective damage removal and further matrix dissolution. Acid solubility, ion concentration, and mineralogical analyses indicate that the sandstone formation in this well has high content of iron-bearing minerals and a moderate content of sensitive clays. Results of core flooding tests conducted on the damaged field cores show that both mud acid and organic clay acid systems show secondary damage on the formation core sample during the acid preflush. Additionally, mud acid shows further damage after the treatment. In contrast, the new fluid system shows consistent damage removal during the treatment with the highest regained permeability. Geochemical simulations also show that more skin reduction is obtained with the new fluid than with the other conventional acid systems tested. Introduction The oil field is located in Maracaibo, Venezuela. The BHST in wells ranges from 220 oF to 240oF. Most of the wells have numerous perforated intervals stretching up to 1000 ft (of which up to 500 ft is perforated). The mineralogy varies from interval to interval, with 4–16% CaCO3, 6–18% clays (mainly kaolinite), 5–10% feldspars, and siderites in some wells (2–5%). The reservoir pressure in zones ranges between 800 and 2500 psi and skin varies across the zones. The rock permeability varies from 1 mD to 200 mD among the zones. The main formation damage mechanisms were identified as fines migration (80–90% production decline after treatment) and CaCO3 scales, mainly due to loss of workover fluids. Currently, various formulations of mud acid, organic clay acid, and solvents are being used to treat these wells with mixed results. The new sandstone acidizing system is developed to effectively treat multi-layered high temperature (200–375oF) reservoirs with long production intervals and complex mineralogy. The benefits of the new sandstone acidizing fluid, which utilizes a novel chemistry, include simplified placement process (i.e., single stage), less precipitation tendency, reduced tubular and production equipment corrosion, and less exposure of hazardous fluids to personnel and the environment at the wellsite. These benefits ultimately lead to a high success rate of sandstone acidizing and sustained production increase from high temperature sandstone reservoirs. A comprehensive laboratory study, which includes acid solubility tests, X-Ray Diffraction (XRD) analysis, batch reaction kinetics, fines migration tests, core flow tests, was conducted on field cores to evaluate and compare the performance of the new sandstone acidizing system with current systems being used in the above oil field.

In Ecuador, the principal reservoirs are subhydrostatic, with permeability ranging from 100 to 2,000 mD and significant clay content. The crude oils are prone to form emulsions in contact with completion fluids. After workover operations-pulling electric submersible pumps (ESP) or recompleting a well-it is common to lose more than 1,000 bbls of completion fluid, resulting in a 20% to 50% reduction in production.Fluid loss control pills containing sized particulate, such as calcium carbonate or sized salt, are frequently used to control the fluid loss; however, a further treatment is required to remove the solids. Using this technique, 25 wells producing a total of 8,000 BPD were worked over, after which the production decreased to 5,000 BPD.The main challenges in developing a solids-free fluid loss control pill to control losses of completion fluid during a well intervention are: a) the low, subhydrostatic (0.16 to 0.36 psi/ft.) reservoir pressure, b) high matrix permeability, and c) cleanup when well is put on production. To overcome this, a highly viscous, polymer crosslinked fluid with an internal breaker was developed to temporarily isolate the reservoirs. Using this fluid, it is possible to work over a well without losing fluid into the reservoirs and having the associated loss of production.In 15 wells worked over using the fluid loss control fluid combined with modified workover procedures, fluid losses were controlled and production was maintained after the workovers. This technique also made it possible to selectively stimulate certain intervals, increasing production. The total production prior to the interventions was 7,300 bpd. Afterward, it increased 27% to 9,250 bpd.The fluid-loss control fluid, together with the new workover procedures, has now been adopted as a standard. It has proved an effective means to protect the subhydrostatic reservoirs in mature fields during workover interventions.

Engineers face many challenges in deciding how to complete Pre-Salt, carbonate reservoirs offshore Brazil. These challenges include: predicting reservoir performance; evaluating well productivity; determining the best completion design strategy; and finally, determining the best matrix stimulation techniques. Matrix acidizing is a common approach to enhance production from carbonate reservoirs. Well defined wormholes bypass near wellbore damage and provide greater reservoir productivity. Poorly known microbial carbonate can impact acidizing diversion and effectiveness in such rock. Optimizing the stimulation process by perforating and acidizing in the correct way in such high-cost projects is a crucial issue for improved well productivity. This paper discusses how effective perforation design positively impacted the evaluation (Well Testing) and acidizing efficiency in such formations. Results from pre and post matrix acidizing PLT logs and transient analysis from downhole and surface well test data demonstrates perforating design efficiency and how it aides in diverting acid over the entire interval compared to another well in the same field.

The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

A gas condensate field in the Sultanate of Oman has been developed since 1999 with vertical wells, with multiple fractures targeting different geological units. There were always issues with premature screenouts, especially when 16/30 or 12/20 proppant were used. The problems placing proppant were mainly in the upper two units, which have the lowest permeability and the most heterogeneous lithology, with alternating sand and shaly layers between the thick competent heterolith layers. Since 2015, a horizontal well pilot has been under way to determine if horizontal wells could be used for infill drilling, focusing on the least depleted units at the top of the reservoir. The horizontal wells have been plagued with problems of high fracturing pressures, low injectivity and premature screenouts. This paper describes a comprehensive analysis performed to understand the reasons for these difficulties and to determine how to improve the perforation interval selection criteria and treatment approach to minimize these problems in future horizontal wells. The method for improving the success rate of propped fracturing was based on analyzing all treatments performed in the first seven horizontal wells, and categorizing their proppant placement behavior into one of three categories (easy, difficult, impossible) based on injectivity, net pressure trend, proppant pumped and screenout occurrence. The stages in all three categories were then compared with relevant parameters, until a relationship was found that could explain both the successful and unsuccessful treatments. Treatments from offset vertical wells performed in the same geological units were re-analyzed, and used to better understand the behavior seen in the horizontal wells. The first observation was that proppant placement challenges and associated fracturing behavior were also seen in vertical wells in the two uppermost units, although to a much lesser extent. A strong correlation was found in the horizontal well fractures between the problems and the location of the perforated interval vertically within this heterogeneous reservoir. In order to place proppant successfully, it was necessary to initiate the fracture in a clean sand layer with sufficient vertical distance (TVT) to the heterolith (barrier) layers above and below the initiation point. The thickness of the heterolith layers was also important. Without sufficient "room" to grow vertically from where it initiates, the fracture appears to generate complex geometry, including horizontal fracture components that result in high fracturing pressures, large tortuosity friction, limited height growth and even poroelastic stress increase. This study has resulted in a better understanding of mechanisms that can make hydraulic fracturing more difficult in a horizontal well than a vertical well in a laminated heterogeneous low permeability reservoir. The guidelines given on how to select perforated intervals based on vertical position in the reservoir, rather than their position along the horizontal well, is a different approach than what is commonly used for horizontal well perforation interval selection.