Fracturing/pressure pumping

Understanding Unusual Diagnostic-Fracture-Injection-Test Results in Tight Gas Fields

In hydraulic fracturing, the use of diagnostic-fracture-injection tests (DFITs) can provide valuable information.

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Fig. 1: Well 1, Stage 2 DFIT injections.

In hydraulic fracturing, the use of diagnostic-fracture-injection tests (DFITs) can provide valuable information. When the measured pressures in such tests are outside the expected range for a given formation, however, a number of possibilities and questions can arise. A recently completed project faced just such a challenge, initially resulting in poor hydraulic-fracturing efficiency and a need to understand the root cause. To this end, a thorough analysis involving a multidisciplinary review team from several technical areas was undertaken, which is described in the complete paper.

Introduction

Block A lies adjacent to other existing hydrocarbon-producing fields, residing within a large recognized basin. Five vertical exploration and appraisal wells were drilled in Block A to a depth of approximately 2400 m. Initially, these appraisal wells were designed for conventional reservoirs. A brief description of the lithology, rock characteristics, and drilling history is provided in the complete paper.

The First DFIT Challenges: Well 1, Stage 1

From the historical regional fracturing-pressure data available, the breakdown and fracturing pressures that would be experienced at the wellhead were predicted to be less than 7,500 psi. During the first DFIT injection operation, the maximum allowable surface pressure was reached without any clear indication of breakdown being achieved in the formation. Several attempts were made to inject into the formation, but there was no effective breakdown and a very low decline rate was subsequently observed.

The high treating pressure observed was initially considered to be potentially a result of plugging of the perforation tunnels or of formation damage. Subsequently, an acid cleanup and an injectivity test were performed with coiled tubing (CT); however, there was no significant positive formation response to this intervention. The wellhead-pressure-­limitation setting was increased to allow a new maximum pressure of 9,500 psi, and the DFIT was attempted once again. A breakdown was finally achieved at a wellhead pressure (WHP) of 8,500 psi, equivalent to a bottomhole pressure (BHP) of 12,341 psi while pumping at 1 bbl/min; a maximum rate of 2 bbl/min was achieved during this DFIT attempt.

A 35-lbm linear-gel system was subsequently injected into the formation to determine if the surface pressures would allow execution of the planned main fracture treatment, but results indicated other­wise. A decision was made to isolate Stage 1 with a sand plug and to proceed to Stage 2 immediately.

Hydraulic-Fracturing and Cleanup Experiences

CT nitrogen lifting was chosen for unloading the wells. The operational details of the fracturing treatments, including minifracture injection, and the well performance during cleanup are described in this summary for Stage 2 and Stage 3 in Well 1. Stage 1 and Stage 2 in Well 2 are described in the complete paper.

Well 1, Stage 2. The target interval for the second stage was also perforated using the 2⅛-in. guns with 6 shots/ft and 45° phasing. The breakdown pressure for the Stage 2 DFIT was measured as 6,800 psi at surface with a BHP of 10,550 psi while pumping at 1 bbl/min. The DFIT was performed successfully with rates of up to 5 bbl/min (Fig. 1 above), even though the fracturing pressures were still high compared with the regional data.

Following the successful completion of the DFIT, a 15% hydrochloric acid (HCl) system was introduced into the minifracture-pumping sequence to improve the injectivity further. The acid system was pumped ahead of the minifracture injection at 5 bbl/min, and a reduction in pressure of 4,100 psi was seen as a result of acid reaction in the near-wellbore region. From the minifracture-injection analysis, a closure pressure of 5,651 psi was selected. The decrease in treating pressure indicates the presence of a substantial acid-soluble restriction, close to the wellbore and potentially formed during well construction.

The main fracture treatment was then performed using 63,000 lbm of 30/50 bauxite and 227,000 lbm of 20/40 lightweight ceramic proppant, at concentrations ranging from 1 to 8 lbm of proppant added per gallon. The treatment was placed successfully with a 35-lbm-­crosslinked-gel system, and the pressure was observed to reduce continually throughout the pumping sequence.

A total of 3,022 bbl of fluid was injected in Well 1, Stage 2 fracturing operations. During the flowback, cleanup, and well-testing stages, a total of 1,460 bbl of this load water was recovered after approximately 7 days. The load fluid from the fracture treatment was not fully recovered because the duration of CT lifting with nitrogen to clean up the well was longer than planned.

Well 1, Stage 3. The third target interval was perforated in six runs with the same approach as that used in previous stages. The WHP observed after perforating was 186 psi, as a result of gas influx. The DFIT of Stage 3 was not carried out because of the presence of the gas in the wellbore and formation disturbance/transient flow after perforating. Instead, a step-rate test (SRT) was performed with 35-lbm/1,000 gal linear gel fluid to determine surface pressures as a function of injection rates.

Following the SRT, a specialized treatment was placed to arrest potential downward height growth during the placement of the main fracture treatment. Given learnings from Stage 1, a 15% HCl stage was pumped ahead of the planned specialized treatment and, once again, a significant reduction in pressure (2,500 psi at surface) was observed as the acid hit the perforations. A stepdown sequence was additionally performed at the end of the injection to ­assess the perforation and near-wellbore friction pressures.

A minifracture treatment immediately followed the specialized-treatment stage, with 200 bbl of 35-lbm/1,000 gal crosslinked fluid being pumped, and the pressure decline was then monitored. Analysis of the minifracture injection gave an estimated closure pressure of 6,337 psi. Subsequently, 120,000 lbm of 20/40 ceramic proppant and 17,000 lbm of 16/20 resin-coated ceramic proppant were used for the main fracturing treatment. The main fracturing treatment was placed successfully using the crosslinked-gel system as planned without issues.

A good pressure history match was achieved. From the estimated geometry, the fracture height created was 35 m with a half-length of 180 m; it was inferred that the previous specialized diversion treatment injected had achieved its design purpose. A total of 2,364 bbl of fluid was injected during the Well 1, Stage 3 operations. During the flowback, cleanup, and well-testing stages, a total of 1,800 bbl of this load water (approximately 76% of injected water) was recovered.

Conclusions

  • Exploration- and appraisal-well design should initially assume that hydraulic fracturing is required, as a base case, until sufficient data have been gathered to demonstrate that the well design can be sized and adjusted to suit the completion technology required.
  • The effects of selected completion techniques and the selection of the initial injection-fluid composition on in-situ-stress interpretation from the DFIT are to be considered in such interpretations.
  • The effect and influence of formation damage on hydraulic fracturing should not be overlooked, despite the fact that the hydraulic-fracturing process ostensibly bypasses such near-wellbore damage.
  • It is hypothesized that conventional drilling methods may be useful in initiating hydraulic fractures when compared with other mechanisms.
  • The application of specialized fracturing treatments to create stress barriers and divert or constrain principal fracture treatments has been confirmed.
  • Conducting in-situ-stress measurements with the wireline-formation-tester microfracturing method can provide early indications of the presence of an abnormal stress state.
  • When combining the openhole wireline-formation-tester microfracturing method with the cased-hole DFIT methodology, the understanding of the stress state, its variation, and its influence on hydraulic fracturing is expected to be improved substantially.
  • Variations in the properties of the formation fluids within the same well and potential reactions with drilling and completion fluids should not be overlooked.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 172956, “Understanding Unusual Diagnostic-Fracture-Injection-Test Results in Tight Gas Fields: A Holistic Approach To Resolving the Data,” by R.N. Naidu, E.A. Guevara, A.J. Twynam, J. Rueda, W. Dawson, E. Moses, and M. Rylance, BP, prepared for the 2015 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 26–28 January. The paper has not been peer reviewed.