Real-time monitoring of hydraulic fracturing using fiber optic distributed temperature sensing (DTS) is starting to be used to estimate fracture initiation depth, vertical coverage and number of generated fractures, effects of diverting agents, and undesired flow behind casing. DTS monitoring of flowback and production can also help to assess the effectiveness of the stimulation treatment. To successfully achieve the monitoring objectives, aspects such as fiber deployment, fiber integrity at high injection rates, location and thermal coupling of fiber with respect to flow path, frequency of data acquisition and resolution, and real-time visualization and modeling need to be carefully considered. This paper presents experiences in the analysis of transient DTS data acquired during high-rate, multi-stage hydraulic fracturing in vertical, deviated, and horizontal oil and gas wells. The location of fiber, conveyed with coiled tubing inside the flow path or cemented behind casing, has a major impact in the temperature response, depending of the thermal conductivity between the fiber cable and the injected fluid path. When the fiber is hung inside casing, the fluid distribution can be challenging, especially if the deepest fluid leak is closer to the bottom of the treated interval, because the temperature along the fiber very quickly becomes equal to the fluid temperature with a minimum gradient straight-line pattern due to high fluid rate and velocity. To overcome this condition the use of induced hot/cold thermal tracers together with temperature modeling has been introduced, allowing the calculation of fluid rate distribution along the perforated intervals. Where the fiber is cemented behind casing, well defined patterns, based on the temperature value, can be recognized to discriminate between flow inside and behind casing, allowing out-of-zone fracture assessment. The thermal coupling of the fracturing fluid inside the casing and the fiber can be very weak at certain levels where small gas "insulation" pockets occur around the fiber, keeping the fiber temperature closer to the geothermal than fluid temperature. At clamp depths or well cemented zones, fiber temperature is much closer to fluid temperature, because the thermal coupling is strong at these levels. When the fracturing fluid flows behind casing, due to bad cement isolation, reaches the fiber cable, the temperature becomes essentially equal to fluid temperature. The advantages and limitations of both cases are discussed based on the type of well, length of gross pay, fracture design, treatment rate, and type of fluids.
Proposal VICO Indonesia is an Oil and Gas Company operating the Sanga-Sanga PSC inEast Kalimantan. This PSC comprises of four operating assets: Nilam, Mutiara, Semberah and Badak. The depositional environment consists of fluvial-deltaicsands with oil and gas bearing sandstone formations stacked on top of eachother, there are on average ten to twenty zones per well. Exploiting thesereservoirs to their maximum potential to meet the gas delivery to Bontang LNGplant is the object of the asset teams. Maximizing asset value by increasingproduction with lower investment is very important within the VICOorganization. In order to achieve the above objective at optimal costs, a lot of emphasisis being given to rigless activities. The main activity is to open thesestacked gas bearing sandstone formations by adding perforations either bywireline or by utilizing extreme under balanced perforating techniques. This paper focuses on the utilization of state-of-the-art software, perforation performance module (PPM) in conjunction with extreme under balanced(EUB) perforating technique for maximizing gas production from the deep lowpermeability and low porosity gas bearing reservoirs. This paper presentsvarious cases showing how effectively and economically these deep sandstoneformations can be completed to maximize the return on investment (ROI). The PPMwas utilized to predict the performance from these reservoirs. The actualpost-job results were then used to verify the predictions. This was essentiallyto assist VICO in making the decisions in line with the economic benefits forvarious perforating techniques. Reservoir Description VICO Indonesia's Oil and gas fields are located in the Kutai Basin, EastKalimantan, shown in Figure 1. The sedimentary system starts fromMiocene age until recent. At the end of the Miocene period the ancient deltawas formed. The delta was formed and moved from west to east, uplift createdfolds. Two of the most common sandstone facies recognized in the Miocenesediments are fluvially dominated, distributary channel and tidally dominated, delta front bar deposits. Commercial hydrocarbons can be produced from highlyquartzitic channel sandstone to a maximum depth of burial of 15,000 ft. Ingeneral, distributary channel facies have a relatively higher porosity comparedto a front bar. The sedimentary system is divided into three sequences. The upper and middlesequences identified have good reservoir quality (porosity and permeability)while the lower sequence has poorer reservoir quality. The lower sequence (deepgas sand) exists in all VICO fields and offers a significant volume of gas tobe exploited. From the petrophysical calculation, permeability is less than 5md and porosity is less than 12% while the pressure is slightlyoverpressured.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDistributed temperature sensing (DTS) coupled with a temperature-pressure simulator has been used successfully to determine flow profiles from multilayered commingled reservoirs in production gas wells. This technology has enabled quantitative individual-layer contributions to gas flow rates and main water entries to be determined, which in turn, has helped engineers to evaluate production conditions, track individual layer recovery, identify problem zones, and plan remedial actions.DTS technology uses fiber-optic cables to measure continuous temperature profiles along the entire wellbore without any cable movement.The real cases presented here include producing gas wells ranging from very low-permeability, hydraulically fractured tight reservoirs to high permeability sands with production rates from one (1) to tens of MMscf/d and over 50 layers per well at depths between 7,000 to 15,000 ft.The analyses have shown that some of the key parameters required to obtain representative flow profiles using DTS can be extracted from the flowing and shut-in DTS transient profiles.Those parameters, which are generally not available in conventional temperature logs, include: (i) geothermal profile; (ii) wellbore and near-wellbore Joule-Thomson effects, and (iii), thermal properties of fluids and formation. Nonproducing, thick zones are particularly useful when calibrating partial flow rates and verifying fluid and formation properties.The flow-profiling model was built around an analyticalnumerical, pressure-temperature simulator that predicts wellbore temperature profiles as a response to individual layer flow rates and sandface fluid-entry temperatures. An interactive error-minimizing technique was used to match the simulated temperatures with the actual DTS profiles. This paper also presents comparisons between the DTSderived flow profiles and the traditional production logging tool (PLT) profiles as well as the value DTS can provide for multilayered gas-reservoir monitoring.
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