Screenless fracturing to sand control. rod shape proppant implementation for unconsolidated mature formations, pannonian basin, Europe

10.04.2018
Источник: Журнал «PROнефть»

Гидроразрыв пласта без установки фильтров как метод контроля выноса песка. Применение цилиндрического проппанта на примере неконсолидированных пластов паннонского бассейна (Европа)

UDC 622.276.66

r. Malon, J. Abbott Schlumberger SER d.o.o., S. Frolov, V. Kulakov NIS a.d., Novi Sad,
P. Vereshchagin Gazpromneft NTC LLC, RF, Saint-Petersburg
Электронный адрес: Vereshchagin.PSe@gazpromneft-ntc.ru 

Keywords: fracturing, soft rock, unconsolidated reservoir, Rod Shape Prop, sand production, skin, mini frac, mature field  

Р. Малон, Дж. Эбботт Schlumberger SER d.o.o., С. Фролов, В. Кулаков NIS a.d., Novi Sad,
П. Верещагин Научно-Технический Центр «Газпром нефти» (ООО «Газпромнефть НТЦ»)

Настоящая статья основана на результатах полевых испытаний, проведенных на одном из зрелых нефтяных месторождений Паннонского бассейна на территории Сербии, разработка, которого началась в 1952 г. Изучаемый объект представляет собой слабо-консолидированный песчаный пласт, высокой проницаемости, эксплуатация которого была осложнена выносом песка и высокой вязкостью добываемой продукции. Пласт сильно истощен, что увеличивает тенденцию к выносу песка. В прошлом традиционные методы борьбы с пескопроявлениями показали себя не эффективными и ухудшали показатели добычи.

Ключевой задачей этого испытания было достижение значительного отрицательного скин-фактора в сильно истощенном неконсолидированном пласте, насыщенном высоковязкой нефтью. Стандартные операции с установкой гравийных систем частично ограничивали вынос песка, а также увеличивали скин-фактор, что негативно влияло на добычу. В пилотных испытаниях применялось ГРП другой модификации - по сравнению с обычными операциями по гидроразрыву с установкой гравийного фильтра. Для обеспечения максимальной проводимости трещин была применена технология ГРП с концевым экранированием трещины (TSO). При эксплуатации после проведения ГРП определялся дебит скважины с оценкой выноса твердой фазы. Если наблюдался вынос песка, тогда устанавливались песчаные фильтры с помощью бригады КРС. После спуска фильтров скважины запускались в добычу. Позже были выполнены успешные испытания с использованием цилиндрического проппанта, что полностью обеспечило контроль выноса песка без установки фильтров и позволило оптимизировать добычу.

Ввиду отсутствия стандартных данных для успешного моделирования ГРП на выбранном месторождении, прогнозирование результатов было затруднено. Ключевую роль играл термокаротаж, который можно провести только при свободном доступе к забою. Анализ результатов пилотных испытаний на приемистость и термокаротажа помогли восполнить недостающие данные. Эти результаты помогли выполнить калибровку геомеханических моделей, что позволило спроектировать схему ГРП.

На текущий момент выполнено 10 скважино-операций. Несмотря на высокую концентрацию проппанта (более 1800 кг/м3), случаев screenout, зарегистрировано не было. Прирост добычи нефти по скважинам от 2 до 5 раз без выноса песка. Скважины обеспечивают стабильный рост добычи в течение первого полугода эксплуатации. В настоящей статье описаны упрощенные методы и технологии, применяемые для обеспечения устойчивого повышения добычи на этом зрелом месторождении

Ключевые слова: гидравлический разрыв пласта, неконсолидированный пласт, цилиндрический проппант, вынос песка, скин-фактор, мини-ГРП, зрелое месторождение

DOI: 10.24887/2587-7399-2018-1-58-63

Introduction

Proppant fracturing stimulation has been being actively used in Pannonian Basin for the last several years. The fracturing candidates were presented by wide range of formation types with different formation properties. In the majority of the cases, the stimulation operations were expanded in the mature oil and gas fields with limited reservoir characterization data.

It resulted data collection on fly for the missing geomechanical formation properties with the following calibrating treatment designs to achieve the proppant placement and production targets. While cumulating the successful experience of enhanced oil production in the mature fields, a new pilot project was launched of using proppant fracturing technique in the unconsolidated sandstone formations to promote both sand control and enhanced production. As results, the first trial operations were completed for oilfield X in the Serbian region of the Pannonian Basin.

General concepts of operations and generic trial well profile

The most of wells were either vertical or deviated well with single perforation intervals (<10 m). There were few wells with multi perforation, up to 4 intervals, total perforation around 50 m. Average formation TVD is around 950 m. The reservoir is represented by moderate permeability unconsolidated sandstone formation. The current reservoir pressure gradient varies in 0.07-0.08 bars/m range. The oilfield has been in commercial production since 1952 s. Both formation depletion and sand production significantly impacts further well production. Proppant fracturing intervention was selected as one of the key methods to extend production life for the active wells in the oilfield. The operations were scheduled without a rig on location as per conventional fracturing completion strategy.

Together with the production increase, fracturing target was also to support sand control management. The frac to sand control concept is based on reduction of the active forces on near wellbore area by modification of the fluid flow from radial to bilinear as per fig. 1. After the fluid flow change, the dominant portion of the production can be transited to the wellbore via high conduction channel such as propped fracture. It allows to reduce pressure drawdown and improve wellbore stability. Additionally, the fracture is completed by more resistant packing in comparison with poorly consolidated sandstone.

Fig. 1. Radial and Bilinear Flow to wellbore: a – Non-fractured well; b – Fractured well

A tip screen-out was designed that promotes enhanced fracture width and maximize fracture permeability. The general planning was based on 2-2.5 tons of proppant coverage per meter of expected fracture height. It resulted 40-70 MT frac treatment executions. 16/30 ISP and 16/30 RCP proppants were selected for the first trial wells.

The formation bottomhole temperature was around 60 degC. A wide range of stimulation and sand control fluid systems are available for this temperature. In the current cases, one of the most common and affordable system was selected which is polymer guar based fluid with borate crosslinker. The fluid was designed to provide sufficient fluid viscosity (400-600 cP at 100 sec-1) to carry proppant on the extreme proppant concentrations up to 1800 KgPA.

The first wells were planned with 2.0-2.6 m3/min pump rate. It was taken into consideration that relatively high leak-off may be met in the moderate permeability unconsolidated formation. As result both pump rate and PAD percentage were in balance to ensure all scheduled proppant placement and enforce maximum fracture conductivity via TSO.

The target fracture properties were set as the following:

Propped fracture half-length – 50-70 m; Dimensionless fracture conductivity – >=1.0; Height – 25-30 m;

Conductivity – 2000-3000 mD·m. 

Mini-fracturing (diagnostic) analysis as a key to successful implementation of the design strategy

Due to maturity of the field, the reservoir and geomechanical data were limited which generated challenging conditions of fracture placement in the unconsolidated formations. The risk of premature screenout was high why attempting TSO. Very often, the geomechanical model was built based on shale volume extrapolation from gamma ray or spontaneous potential logs. Sonic log data was not available except few occasional cases when compressional sonic travel time (DTC) was recorded. The mini-frac was an essential step to collect more information which was needed for job execution.

Fig. 2. Diagnostic Injections prior Main Frac 

The mini-frac analysis involves 2 steps: breakdown and calibration diagnostic. The fracture was initiated on breakdown stage. The breakdown was performed with the treated water which contained clay stabilizer and surfactant. This step allows to estimate preliminary fracture closure. The crosslinked fluid efficiency and closure were confirmed during calibration injection. 100-200 KgPA small sand slugs were included into calibration injection in order to verify potential bridging issues. The injection data was analyzed with optimization of simulation model in order to achieve good matching between calibration execution record data and simulation results for the same scenario.

The accuracy of stimulation model calibration increased significantly due to ability to perform post injection temperature logs. In spite of frac and pack operations, the screenless fracturing provides free access for the well logging. The fracture height could be identified in this case. With the other data (fluid efficiency, closure stresses, Net pressure), a stimulation model could be calibrated with the adjustment of main frac preliminary design even though the initial data package was poor.

The exclusive design was selected for each individual well. The new findings and cumulative experience were implemented in the each further well accordingly. Finally, all treatment were calibrated on fly as per actual pressure response while pumping and real time model adjustment by engineers on wellsite.

On the fig. 2 you can see the execution plot of the first job. As it was mentioned, the pump rate was balanced to provide both placement and TSO packing. Once it was observed on fly that treatments is smooth with the 2.4 m3/min pump rate, the rate was forced down to promote fracture closure and proppant packing.

The rate was dropped gradually up to 0.5 m3/min at last 1500 KgPA final prop concentration. In this particular case, the shut down was called 2 m3 earlier before the designed in the flush. Several min time was given for partial fracture closure. Then the well was completed at 0.5 m3/min to squeeze NWB area.

Based on the first trial results, the following fracturing design was optimized to promote tip screenout proppant packing. The pump rate and clean fluid reduction volumes were changed as a key parameters.

Additionally, the next treatments were planned with live annulus completion without packer installation for fracturing execution according to verified well integrity calculations. It allows to monitor BHP pressure behavior in real time through the annulus response while using hydrostatic pressure offset. Beside the technical advantage, this step allowed to simplify workover operations prior the treatment and eliminate the packer related costs.

As you can see on the fig. 3, the annulus pressure represents bottomhole pressure with the offset of annulus hydrostatic. It supports more accurate fracture modeling with reduction of design failure risk while performing tip screenout treatments.

After the successful set of operational job deliverability and positive production result observations, the following step was performed to maximize fracture conductivity and increase chances of post frac screenless well performance. The further optimization has been performed via introduction of unconventional shape proppant type such as RodPROP*.

The RodPROP was able to provide strong fracture conductivity increase in comparison with other ceramic proppants and 16/30 RCP in particular (~1800 D vs ~600 D pack permeability for Jermenovci reservoir stimulation case). It enhances near wellbore stability and proppant flowback control via interlock mechanical interference of cylindrical proppant particles without a need of chemical bonding. This was strong advantage on Jermenovci field where resins consolidation was challenged by both relatively low temperature (60-62 degC) and low stresses (<2500 psi). Additionally, RodPROP improves fracture clean up as per enhanced fracture conductivity and better resistance to the driving forces (fig. 4).

Fig. 3. TSO Fracturing with Live Annulus and Forced Rate Reduction

The rod shape proppant was implemented into design as replacement of 16/30 RCP proppant. RodPROP ratio was around 30   of total proppant volume. No additional actions were needed from the design or execution side. The post job evaluation indicated significant Fcd increase of treatments with RodPROP. As per comparison of 2 wells in the same area and the same job size, the fracture Fcd was estimated while using RodPROP and 2.2 Fcd for the 16/30 RCP case. Also, the RodPROP case well was put into production without the screen while screen was set for the second comparison well.

Workover post fracturing well operations

The screenless fracturing is rigless operation. It means that fracturing fleet and workover rig can be scheduled independently. It provides flexibility of planning what is not possible with the common frac & pack services.

After the completion of fracturing operations, the frac fleet was rigged down and moved to the next well as per fracturing schedule. Afterwards, the workover was mobilized to the treated well for clean up operations. The post treatment workover operations included the following stages: frac string POOH, wellbore cleanup with hydrostatic bailer, flowback testing and production completion setup. 

Fig. 4. Rod shaped proppant (а), Conductivity Limited Fractures (b) and Higher-Productivity Pack (c) 

The solid flowback was verified during the flowback stage by measuring solid content in liquid production and actual well bottom tagging before and after the flowback stage. It was tested on flowback rates with gradual increase from 10 to 25 m3/day.

The proppant flowback issues were still identified for the majority of wells completed with resin coated proppant. In this case the wellbore was cleaned out and gravel screens were installed according to the proppant size specification. No solid production issues were observed for wells completed with the Rod Shape Proppant. As result, this wells were put into production directly after production completion installation.

Production results 

By now, ten wells have been completed already in the oilfield X. The first wells were treated in Q3 2016 (fig. 5). Based on result observation, a few candidates are being selected each quarter since that time with ongoing operations up to date.

The current methodology has proven a stable fluid production enhancement with no pump failure due to solid flow. The oil production increment varies from 2 to 5 times. The results were beneficial in comparison with previous gravel pack operations which improves sand control management only. 

Fig. 5. Fluid Production indexes (a), Water Cut (b)

In the most cases, -4 to -5 skin could be obtained by fracturing for current reservoir conditions. Average post frac production index is around 0.3 m3/days/bars. The controlled placement of the frac geometry allows to maintain relatively similar water cut as before the treatment. The general production reference can be found in the plots below. 

Summary

The TSO fracturing stimulation operations enable to extend production life for the mature oilfield in Pannonian basin which has been developed for 60ty years. It reduced a sand production risk which is one of the key challenges on the field. If any solid flow potential was still identified after fracturing, the screens were installed additionally. Later, the stimulation design optimization and RodPROP implementation in tail-in promoted screen free wellbore completion. Overall, ten wells analysis indicates 330   production increase after operations with already available a year history of intervention free constant production performance.

The current methodology was the most time and cost efficient for the current mature field. The rigless stimulation with screen free completion allowed to perform diagnostic injections with temperature logs that resulted fracture height confirmation. Based on mini-fracturing collected data, the missing reservoir and geomechanical data was compensated with significant accuracy increase of stimulation model calibration. As result, TSO fractures were placed successfully as designed. No cases of premature job terminated or well watering out were in place. In the same time, the flexibility on planning was available as per rigless fracturing with followed workover operations on flowback, potential screen and production set installation. Workover and fracturing were planned independently that allows to save around 2 operational days per well for each service during the multi well ongoing frac campaign. The sequential operations reduced effective wellsite area requirements up to 50   with the following project cost saving as well.

Initially, the sand screens were still required as per flowback analysis. Even though, the local operator screens were satisfied in terms of specification since it wasn’t exposed to high rate/high pressure pumping with abrasive fluids in spite of standard frac and pack operations scenario. The Rod Shape Prop implementation allowed to have fully screen free completion without solid production. It provided an additional optimization on the completion costs and workover operational time.

The described case study resulted the significant milestones in production optimization and efficient sand control management for the oilfield X in Pannonian basin. More wells are scheduled to be treated recently and in near future.

The summarized experience and methodology can be used a reference for the other fields which requires production to be enhanced in the unconsolidated formations with sand control management. It also provides an a engineering guidance how such operational can be completed effectively even if the initial input data is very limited with high initial risk for conventional frac and pack operations.


Авторы статьи:  r. Malon, J. Abbott Schlumberger SER d.o.o., S. Frolov, V. Kulakov NIS a.d., Novi Sad,
P. Vereshchagin Gazpromneft NTC LLC, RF, Saint-Petersburg
Источник:  Журнал «PROнефть»

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