Improving hydraulic fracturing effectiveness in depleted and low-pressure reservoirs using N₂-energized fluids

Abstract

Foamed and energized fluids fracturing has been used in both conventional and unconventional reservoirs, as they reduce the amount of water used and hence minimize deleterious impact on water-sensitive formations. They also aid in the flow back after treatment in reservoirs where drawdown is limited. In this paper, the most important foam properties are presented, in addition, when to use energized fluids fracturing and how to choose the best energizing component with the best quality. The impact of N₂-energized fluids fracturing (NEF) on wells that were previously fractured using conventional fracturing fluids is also presented. In addition, a comparison between the results of N₂-energized fluids fractured and conventional fluid fractured wells is presented. The effect of using 20 to 50% (NEF) on production through surface well testing and live production data showed excellent and sustainable production rates. An economical study is presented through comparing the total capital cost of both NEF and conventional fluids fracturing, in addition to the hydrocarbon recovery of wells after both types. Data considered in this work represent about 40 wells fractured using NEF in the Egyptian Western Desert.

Introduction

Foam stimulation became one of the major techniques used for fracturing oil and gas wells. Foam is a dispersion of gas phase inside liquid phase, where CO₂ or N₂ gas is the internal phase, and liquid such as water, oil or even alcohol is the external phase (Gandossi. 2013). During foam production, a compatible surfactant must be used to combine both phases to maintain foam stability during the treatment as illustrated in (Montgomery. (2013)). Generally, most of the foam properties including its rheology and viscosity are controlled by the foam quality, which is the percent of gas phase volume to the total volume of fluid used (gas + liquid). The foam quality is given by:

$${\text{Foam quality}} = \frac{{V_{{{\text{gas}}}} }}{{V_{{{\text{gas}}}} + V_{{{\text{liquid}}}} }}\%$$

(1)

As illustrated in (Mitchell. (1969)) & (David and Marsden 1969), N₂ is the oldest foaming gas, and its use dates to 1960 as indicated in (Petty et al. 1964). The other gas commonly used is CO₂ and its use started in the early 1980s as represented in (Bullen and Lillies 1983). Due to flow-back challenges in low-pressure formations, foam-based fluids become very common for use in low-pressure reservoirs. Recently, the US Department of Energy (DOE) is focusing to identify a thermodynamic pathway to utilize natural gas (NG) obtained from producing wells in foam fracturing (Beck and Verma 2016) & (Verma 2016). Later, the study was extended into laboratory-scale experiments to measure NG-foam fluid rheology, and it was found to be similar to foams based on N₂ and CO₂ (Beck, et al. 2017). The use of NG as an energizer has not been practiced widely yet, but applications of NG foamed field test and reaping the economic benefit from simplified logistics and improved production would enable operators to invest in improving the use of NG foams for wellsite treatments.

Typical foams exist when the foam quality ranges between 52 and 95%, and at foam qualities greater than 95%, the gas becomes the external phase and referred to as mist flow as illustrated in (Economides and Nolte 2000). Stable dispersions of gas in liquids can also be prepared with qualities less than 52% which can be called foams or energized fluid as in (Watkins et al. 1983).

A hydraulic fracturing treatment can be energized by introducing a compressible gaseous component into the treating fluid. The gaseous component inside the energized fluid treatment expands when the treatment is completed and pressure is released. This facilitates the flow back of treatment fluids post-treatment. Energizing the fracturing fluid can be used for many reasons, but mainly its applications are in reservoirs that have a low pore pressure, low permeability or water-sensitive formations.

Stimulation of depleted and low-pressure reservoirs became one of the most important challenges in the past decade. When using conventional fluids in fracturing these reservoirs, the results were very disappointing, due to the formation damage caused by these fluids and the disability of reservoir pressure to overcome the fluid column in the well, as well as flow-back fracturing fluids after treatment.

Recently, energized fluid fracturing showed very good and satisfactory results in depleted and low-pressure reservoirs. In addition, it showed excellent production results when used in high-pressure reservoirs. The use of ${\text{CO}}_{2}$ or ${\text{N}}_{2}$ in energizing fluids in foam fracturing can reduce the amount of water up to 90% (depending on the foam quality). This consequently reduces the damage caused by water in low-pressure reservoirs. They are becoming very popular for use in stimulation treatments of depleted and low-pressure reservoirs. This is due to their excellent properties such as low leak-off rates, excellent proppant transfer capacity, longer fractures with less fluids, minimum formation damage and superior energetic post-treatment cleanout.

Energized fluids properties

Composition and rheology

The most popular foams are made from nitrogen, water and a foaming surfactant. At first, the surfactant is mixed with the liquid phase, and then, the injection of both gas and surfactant solution into the well (Haugen 2014) explains this operation in detail. Simple water foams have low viscosity relative to gelled water foams and a shorter half-life. They are used in shallow wells with low bottom-hole temperatures, and where only low proppant concentrations are required. They are also used in wells where damage due to gelling agent is critical. Adding a gelling agent extends the half-life of the foam for treatments of linear gel (non-cross-linked) which gives increased viscosity to foams over that of water-only foams. The additional viscosity produces greater fracture width to allow higher proppant concentrations to be placed. The use of delayed cross-linking agents in foam fluids greatly multiplies the viscosity obtained by foam fluids. The higher viscosity fluid creates greater fracture width for easier proppant placement and lower fluid leak-off. Sand concentrations as high as 12 lb/gal have been successfully placed. The cross-linked gel liquid phase imparts much longer half-life to the foam and leaves a cross-linked gel filter cake. So, it is important to break the gel prior to flow back. Failure to break the gel will limit the fluid recovery.

Figure 1 illustrates viscosity generated in water foamed with N₂. Little viscosity increase is noted until the gas quality gets above 52%. Above 52% quality, the viscosity increase is exponential. Viscosity also decreases with shear rate, showing that foam is a shear-thinning-type fluid, i.e., foam viscosity is low in high-shear conditions such as pumping down tubing and higher in low-flow, laminar condition such as flowing down a fracture system carrying proppant. Cross-linking the liquid phase will compensate for the decrease in viscosity caused by using low foam qualities that are less than 52%. This makes it possible to use foam qualities less than 52% with higher viscosity and good proppant carrying capacity.

Fig. 1

Effect of foam quality on foam viscosity (Steven et al. 1983)

Proppant carrying capacity

In foam fracturing, the viscosity of the created foam is much more than each of the single phases comprising the foam. This gives foam a higher viscosity than other conventional fracturing fluids such as water. This assists in even mixing of the fracturing fluid during the treatment and reducing proppant sedimentation. Slick-water fracturing creates longer fractures compared to N₂-energized treatments, but leaves much of the fracture length created un-propped compared to the N₂-energized treatments; therefore, foams and energized fluids are more suitable than slick-water in carrying proppant throughout the fractures. According to (McAndrew 2014), the proppant distribution inside the created fracture is of great importance as it affects the reservoir performance. Foam and energized fluids create the optimum desired proppant distribution inside the fracture with high proppant concentration, compared to other conventional fracturing fluids as illustrated in (Yu 2015).

Energized fluids selection and quality control

Applications of energized fluids over conventional fluids

The use of energized fracturing fluids is determined based on the drawdown level in the formation, which is classified high or low based on the capillary pressure, which in turn is a function of formation permeability. For drawdown pressure lower than the capillary pressure limit, energized fracturing is highly recommended. In the case that the drawdown pressure is high (more than the capillary pressure limit), it makes no difference to use energized fracturing over conventional fracturing, where the conventional fracturing fluids would give the same results. As the drawdown is sufficient to recover the fracturing fluids after treatment, the use of energized fracturing can be justified to tight and low-pressure formations.

Choosing the best energizing component

After determining that energizing the fluid is the way to go, it is necessary to evaluate which energizing component works best. In this section, we evaluate the most popular energizing components: N₂, CO₂ and binary systems of both N₂ and CO₂ as illustrated in Table 1. It is obvious that N₂ is more familiar, available and easier to handle than CO₂. However, CO₂ is preferred to use over N₂ if the adequate environment and equipment are available due to:

• Higher solubility in water.

• Compatibility with formation fluids.

• Lower surface treating pressures.

• Accessibility to deeper reservoirs.

• In addition, it is considered an EOR method as it dissolves in oil and decreases its viscosity.

Table 1 Advantages and limitations of the most popular energizers

Choosing the optimum foam quality

After deciding that energized fluid fracturing is the way to go and determining which energizing component works best, now it is time to determine the optimum foam quality to be used. Studies showed that longer but thinner fractures result from lower quality (20–30%) and shorter but more conductive fractures result from high quality (60–70%). For most tight reservoirs, it is required to have a longer and thinner fracture to increase the contact area with the reservoir; this is why the lower quality fluids are preferred.

To conclude, 30 to 50% quality energized fluids are recommended because they allow enough gas to saturate the liquid while giving the best fracture dimensions for tight reservoirs. Higher quality (up to 70%) may be necessary if shorter and wider fractures are required.

Objectives of this study

The objectives of this study are to demonstrate that:

• 1. 20 to 50% quality energized fluids are optimum for use in the Egyptian Western Desert.

• 2. NEF fracturing succeeds to recover oil from previously fractured wells using conventional fracturing fluids. In addition, a comparison between the results of NEF fractured and conventional fluid fractured wells is presented, through testing and live production.

• 3. Adding a component such as methanol to an energized system would help in fracturing tight gas reservoirs where aqueous phase trapping is a potential problem.

• 4. NEF treatments are more economically preferable than conventional treatments in terms of overall cost.

Field applications

In Egypt, where ${\text{ CO}}_{2}$ is not used due to the mentioned reasons in the previous section, only ${\text{N}}_{2}$ is used in energizing the liquid phase to fracture depleted and low-pressure reservoirs with foam qualities ranging from 20 to 50%. Foam quality is limited to this range because the follows:

• 1. Previous studies showed that under a wide range of reservoir conditions, foam qualities of 20 to 50% are optimum because they allow enough gas to saturate the liquid, to maximize gas flow back, and they yield long fractures. Higher quality (up to 70%) may be necessary if shorter and wider fractures are required (Kyle et al. 2009).

• 2. Increasing foam quality will require larger supply of gas, special surface and subsurface equipment.

Effect of using NEF fracturing in Egyptian Western Desert

This section reflects successful applications of using 20–50% quality ${\text{NEF}}$ in the Egyptian Western Desert. NEF showed very good and satisfactory results when used in stimulating low-pressure reservoirs as well as high-pressure ones. The following section shows the rise of using NEF in fracturing low-pressure reservoirs in the Egyptian Western Desert. It was started by 2 wells that were fractured using conventional fluid fracturing, but showed very disappointing results in both production and sustainability. They were then stimulated using NEF fracturing. Their impressive results made NEF fracturing the ideal choice to stimulate depleted and low-pressure reservoirs.

Wells (B-01 and B-02) were drilled in the same block (B) targeting the same reservoir ARG. Figure 2 illustrates the topographic map for the well in block (B).

Fig. 2

The topographic map for block (B)

Well B-01 successfully encountered the primary targeted sand on upper-ARG level of about 22.6 m net sand with good quality (average porosity = 0.19%) and reservoir pressure found around 1400 psi. Well B-02 successfully encountered the primary targeted sand on upper-ARG level of about 6 m net sand, with good quality (average porosity = 0.16%) and reservoir pressure found around 1400 psi. At first, the two wells were stimulated using conventional fracturing fluid, and Figs. 3 and 4 show the well logs and the completion summary for the two wells, respectively. Table 2 illustrates the data for the first conventional fluid fracturing for both wells. It indicates very low average gel fluid retained factor, which indeed affects the fracture conductivity, as it will appear in the production data of the two wells.

Fig. 3

The well logs for Well B-01 and Well B-02

Fig. 4

Well bore diagram with formation tops for Wells B-01 and B-02

Table 2 The fracturing data of the first conventional fluid fracture for Well B-01 and Well B-02

Results and discussion

Both Well B-01 and Well B-02 were tested after their first conventional fluid channel fracturing. Their production data showed very low and declining rate with time, and the production data for Well B-01 after the first conventional fluid fracturing while lifting with ${\text{N}}_{2}$ showed oil rate of 7–70 BOPD. While the production data for Well B-02 showed oil rate of 50–600 BOPD. The production rates of both wells were very low and declined rapidly. After these disappointing results of the conventional fluid fracturing, both wells were re-fractured using ${\text{NEF}}$ and showed exceptional results. The challenge was to bypass the damage caused by the first conventional fracturing fluids and achieve good and sustainable production rates despite their low reservoir pressures. Table 3 demonstrates the re-fracturing data for both wells.

Table 3 The re-fracturing data for Well B-01 and Well B-02

The production figure of Well B-01 after NEF re-fracturing showed a gross rate of 720 BPD, which sustained for nearly one year, while the production figure of Well B-02 after NEF re-fracturing showed a gross rate of 520 BPD, which sustained for 9 months.

As demonstrated in Table 4, NEF fracturing showed very good and sustainable production results compared to those of conventional fluid fracturing as follows:

• 1. Both wells showed very good and sustainable rates after NEF fracturing compared to their results after conventional fluid fracturing.

• 2. The fracture half-lengths $X_{f}$ for Well B-01 and Well B-02 obtained from NEF fracturing are 87 m and 190 m, respectively, which are nearly double the half-lengths obtained from conventional fluid fracturing using the same liquid volumes.

• 3. The fracture conductivities for Well B-01 and Well B-02 obtained from NEF fracturing are 53,720 md.ft and 59,817 md.ft, which are nearly double that obtained from the conventional fluid fracturing.

• 4. The average gel retained factor is higher in case of NEF fracturing for both wells (0.8 and 0.6), respectively, than in case of conventional fluid fracturing (0.6 and 0.3), which is the percent of gel fluid extracted after treatment. The higher this percent, the lower the residual gel material left in the formation, which affects the fracture conductivity.

Table 4 Comparison between conventional fluid and NEF fracturing for Well B-01 and Well B-02

Successful applications of NEF fracturing in the Egyptian Western Desert

After the impressive results of NEF fracturing in Wells B-01 and B-02, it is now a role of thumb to use NEF in fracturing low-pressure reservoirs to minimize the formation damage and aid in the flow-back operations after treatment. Table 5 shows a summary of successful applications of NEF in fracturing low-pressure reservoirs in the Egyptian Western Desert. Figure 5 summarizes pre- and post-energized fluid fracturing gross rates for a sample of wells in the Egyptian Western Desert.

Table 5 Pre- and post-NEF fracturing results for successful applications in the Egyptian Western Desert

Fig. 5

Summary of pre- and post-fracturing gross rates for a sample of successful applications in the Egyptian Western Desert

Well O-01 gas producer was a special challenge. Well O-01 successfully encountered the primary targeted sand on lower SAFA level of about 26.5 m net sand with moderate quality (average porosity = 0.08%), reservoir pressure found depleted around (3300 psi) and very tight (0.2 md). Figure 6 illustrates the topographic map for L-SAFA formation, and Figs. 7 and 8 show the well log and completion summary for Well O-01, while Table 6 illustrates its reservoir and petro-physical data, which indeed requires a special type of stimulation.

Fig. 6

The topographic map for lower SAFA formation top

Fig. 7

Well O-01 open hole log

Fig. 8

Well bore diagram and formation tops for Well O-01

Table 6 Reservoir and fracturing data for Well O-01

The limited drawdown led to deciding that energizing fluid fracturing is the way to go, but another issue was encountered which is the APT (aqueous phase trapping) due to the very low reservoir permeability. Adding a component such as methanol to the energized fluid system could help. The final decision was made to stimulate that well using foam-methanol fracturing, where 10% methanol was added to the fracturing fluid before energizing with 25% quality ${\text{N}}_{2}$. Well O-01 showed good enhancement in gas production rate, as shown in Fig. 9 a, quick comparison between pre- and post-fracturing gas rates, where pre-fracturing gas rate was 0.5 MMSCFD, while post-fracturing gas rate was 2.8 MMSCFD with a FOI equal to 5.6.

Fig. 9

Pre- and post-NEF fracturing rates for Well O-01

Economic benefits of using NEF fracturing

Granting the very impressive results of NEF in fracturing depleted and low-pressure reservoirs on production rates and sustainability. NEF fracturing treatments appear to be more economically preferable to conventional fluid fracturing ones.

In this section, we will take a sample of wells to discuss the economic benefits of using NEF fracturing over conventional fluid fracturing in depleted and low-pressure reservoirs.

Wells A-01, A-02 and A-03 were drilled in the same reservoir block, targeting ARG formation. Figures 10 and 11 show the topographic map and the well logs for the three wells, respectively, while Fig. 12 shows the well completion summary for the three wells. Wells A-02 and Well A-03 were stimulated using conventional fluid fracturing, while Well A-01 was stimulated using 35% NEF fracturing. As shown in Table 7, it is obvious that treatments of the three wells used nearly the same liquid volumes and proppant mass. The treatment cost of NEF fracturing is about 15–20% much more than that of conventional fluid treatments. However, this additional cost is offset by the cost of unloading and flowing back the well in case of conventional treatments. Also NEF treatments showed very impressive estimated ultimate recovery (EUR), these reasons make NEF treatments more economically preferable than conventional ones.

Fig. 10

Topographic map for Wells A-01, A-02 and A-03

Fig. 11

Well logs for the 3 offset wells: Well A-1, Well A-2 and Well A-3

Fig. 12

Well bore diagram for the three Wells A-01, A-02 and A-03

Table 7 Fracturing and economic data for Wells A-01, A-02 and A-03

Figure 13 shows the cumulative production from the three wells during a three-month period, represented as a fraction of original oil in place (N). Well A-01 produced about 0.016 N gross production, while Wells A-02 and A-03 produced about 0.009 N and 0.0092 N.

Fig. 13

Cumulative production of the three Wells A-01, A-02 and A-03 for a period of 3 months

Conclusions and recommendations

Based on the field data conducted and presented in this paper, the following conclusions can be drawn:

• 1. 20 to 50% quality NEF fracturing showed exceptional results mainly in low-pressure reservoirs in the Egyptian Western Desert, in addition to their good results in high-pressure reservoirs.

• 2. Adding a component such as methanol to an energized system helps in fracturing tight gas reservoirs where aqueous phase trapping is a potential problem as the case in Well O-01.

• 3. NEF treatments are economically preferable than conventional fluid treatments.