No abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn 2004, SPE 90238, "Perforating and Hydraulic Proppant Fracturing in Western Siberia, Russia," provided recommendations for perforating in Western Siberia, 1 an area where hydraulic fracturing is booming and considered second only to the North America region, with over 5,000 fracturing treatments performed each year. One of the issues that has become obvious over the past two years is the limited understanding of the importance of using well and reservoir data as major factors in the selection of perforating programs to prevent premature screenouts.In recent years, several operators have concluded that maximizing production from most wells in western Siberia fields requires the placement of large quantities of coarsesized proppant using the least damaging fluid systems possible in the fracturing applications. For production optimization, the proven trend is "larger (proppant sizes) and bigger (jobs)" using the lowest acceptable polymer loading in the frac fluids to minimize gel damage.To achieve successful placement of the designed optimized fracturing treatment, all factors that could lead to a premature screenout should be eliminated. Improper perforating practices have proven to be one of the primary limitations and are often proven as the number one reason for past screenouts. Using the preferred perforating guns and charges for a specific application reduced the total screen-out percentage to less than 5%. The key to proper selection of perforating methods included using API RP 19B data and simulation software that calculates downhole conditions. This paper describes several case histories in moderately hard and moderately soft rock reservoirs, using both big hole and deep penetrating guns, showing results that proved using proper perforating practices could eliminate screenouts. Furthermore, the authors describe how a different approach (hydrajet perforating) was used to provide entry from the wellbore to the formation. Hydrajetting will be compared with conventional (shape-charge) perforating techniques prior to hydraulic fracturing. Case histories for multi-zone pin-point stimulation will be provided.

Many oil producing wells, globally, experience sand production problems when reservoir rock consists of unconsolidated sand. Several wells in the Dzheitune oil field are experiencing a similar challenge. Production of formation fines and sand has caused accumulation of fill and wellbore equipment failures and has necessitated periodical and costly coiled tubing-assisted wellbore cleanout operations. A novel chemical treatment tested in the oil field to tackle the challenge led to positive results. A well with a relatively short target perforation interval was selected as a candidate for the trial sand conglomeration treatment to avoid any uncertainties related to zone coverage. Pre-requisite sand agglomeration and chemical-crude oil compatibility laboratory studies were carried out to optimize the main system and preflush fluid formulations. Once the laboratory testing was complete, a step-rate test was performed to determine the maximum injection rate below formation fracturing pressure. The chemical systems were prepared using standard blending equipment. The preflush fluid was injected to prepare the treated zone. The main fluid was then injected into the reservoir in several cycles at matrix rate by a bullheading process. Upon completion of the treatment, the well was shut in for several days for optimal agglomeration (conglomeration) before the well was slowly put on production. A long-term increase in the productivity index and sand-free flow rate with no damage to the wellbore or the reservoir were observed. The technology demonstrated its efficiency in preventing and controlling sand production; avoiding frequent, time-consuming, costly wellbore cleanout operations; and producing hydrocarbons at reduced drawdown pressure.

The target reservoirs are several limestone layers separated by shales and extend over a vertical height of up to 100 m. The reservoirs are developed differently in almost every well, and natural fractures exist in some, but not in all, wells. The wells are completed with regular 13 3/8-in. casing to around 900 m, 9 5/8-in. casing to around 3400 m, and a 7-in. liner through the reservoir section at around 4100 m. Surface temperatures range from +20°C in summer to -50°C and lower in winter, with bottomhole temperatures (BHTs) around 50°C. Both for producers as well as injectors, a properly designed matrix acid treatment covering the entire reservoir proved to be the most successful production enhancement technique. Most of the wells were completed in a way that allowed the matrix acid stimulation treatments to be conducted in two stages. Both stages covered more than one perforation set. However, for the second stage the job team had to consider that the first stage covering the lower zones was already completed, and fluid would most likely be pumped into this lower zone. The challenge was to provide good diversion over the entire reservoir for one stage and, even more difficult, to divert the majority of the acid into the upper zone for the second stage. In addition, this reservoir oil has relatively high paraffin content, and paraffin deposition, hindering if not eliminating production, will occur below a certain temperature. This fact had to be considered in the matrix acid stimulation design. For a single-stage treatment, or the treatment of the lower zones, a combination of Insitu Crosslinked Acid (ICA) and maximum pressure/maximum rate technique (MPMR) proved to give excellent diversion over these intervals. ICA is a chemical diversion technique. It features a thin, gelled acid with a viscosity of approximately 25 cP that forms a highly viscous crosslinked gel when the acid spends on the formation to a pH of approximately 2. The crosslinked gel can effectively stop any further fluid invasion, and following acid stages will be diverted to different parts of the zone. As the spending continues further, the crosslink will break again at a pH of approximately 4. The MPMR technique uses the concept of dynamic diversion, whereby the pressure remains constant just below frac pressure, and the rate is increased as the acid spends on the formation. Bottomhole (BH) gauge data are available to show the effect of diversion and eliminate any possible effects from friction and hydrostatic pressures that can affect surface data. For the treatment of the upper zone, when the lower zone was already stimulated and could not be isolated by mechanical means, additional diversion was required to seal off the perforations of the lower zone. A combination of Biodegradable PerfPac Balls and ICA was pumped at the beginning of the treatment to divert the remaining matrix acid treatment away from the lower zone and optimize stimulation of the upper zone. This paper shows how a properly engineered matrix acid treatment using a combination of diversion techniques can result in optimized stimulation treatments. In a carbonate formation, efficient diversion of acid fluids is even more important than in a sandstone reservoir because the acid-carbonate dissolution reaction rate is so fast. Introduction One of the most important factors affecting the success or failure of any matrix acid treatments is the correct downhole placement of the acid for optimum zonal coverage. This will depend largely on the completion design that is being run on a specific well, but also on formation and reservoir issues; e.g., certain completion scenarios eliminate a potential use of packers for isolating two zones of interest. In this case other means of stimulating both zones effectively must be identified and optimized.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn 2004, SPE 90238, "Perforating and Hydraulic Proppant Fracturing in Western Siberia, Russia," provided recommendations for perforating in Western Siberia, 1 an area where hydraulic fracturing is booming and considered second only to the North America region, with over 5,000 fracturing treatments performed each year. One of the issues that has become obvious over the past two years is the limited understanding of the importance of using well and reservoir data as major factors in the selection of perforating programs to prevent premature screenouts.In recent years, several operators have concluded that maximizing production from most wells in western Siberia fields requires the placement of large quantities of coarsesized proppant using the least damaging fluid systems possible in the fracturing applications. For production optimization, the proven trend is "larger (proppant sizes) and bigger (jobs)" using the lowest acceptable polymer loading in the frac fluids to minimize gel damage.To achieve successful placement of the designed optimized fracturing treatment, all factors that could lead to a premature screenout should be eliminated. Improper perforating practices have proven to be one of the primary limitations and are often proven as the number one reason for past screenouts. Using the preferred perforating guns and charges for a specific application reduced the total screen-out percentage to less than 5%. The key to proper selection of perforating methods included using API RP 19B data and simulation software that calculates downhole conditions. This paper describes several case histories in moderately hard and moderately soft rock reservoirs, using both big hole and deep penetrating guns, showing results that proved using proper perforating practices could eliminate screenouts. Furthermore, the authors describe how a different approach (hydrajet perforating) was used to provide entry from the wellbore to the formation. Hydrajetting will be compared with conventional (shape-charge) perforating techniques prior to hydraulic fracturing. Case histories for multi-zone pin-point stimulation will be provided.