Production Case Study

Given the production challenges faced by Target A, the key questions of this study are:

1. Can we better understand and quantify the potential expected ultimate recovery?
2. What best practices can be identified, and possibly implemented, from better-performing global reservoir analogues?
3. What lessons can we learn from poorer-performing global reservoir analogues?

Based on data provided, both text and numeric parameters have been standardized and classified using the consistent rules of C&C Reservoirs’ comprehensive classification scheme. Initial analogue selection is based on a broad set of parameters to establish a trend in recovery factor. The following selection criteria (Table 1) have been used to identify appropriate analogues. From this selection, 25 relevant global analogues were identified.

One of the key production challenges facing the redevelopment of Target A is the control and management of water production. Water-cut performance from analogues can offer significant insight into conformance-improvement best practices. The analogue selection is then further refined to focus on a narrowly defined set of parameters (Table 2).

Thirteen relevant global analogues were selected, and the production characteristics of these analogues are given in Table 3. Most analogues have a relatively short plateau duration of 12-67 months with an average of 24 months. Plateau annual recovery (% of in-place oil) ranges from 1 to 4% with an average of 1.4%. Horizontal wells adopting cased-hole completions represent the most effective option for field development.

The recovery efficiency chart shows two trends in water-cut performance (Fig. 3): (1) early water breakthrough evident in a rapid rise in water-cut; and (2) a gradual rise in water-cut. The poorly-performing analogues are characterized by relatively low plateau annual recovery ranging from 0.9 to 1.2% (of STOIIP) and high initial saturation of 40 to 50%, and, owing to a lack of effective water control, only achieved an ultimate recovery factor of <15% (Fig. 4). In contrast, the better-performing analogues are characterized by higher plateau annual recovery ranging from 1.5 to 2.5% (of STOIIP) and have adopted effective reservoir management practices and achieved a higher ultimate recovery factor of >28% (Fig. 4).

The final step of the workflow is a detailed examination of best practices and lessons learned. Three analogues with similar reservoir characteristics and production challenges to Target A have been selected to demonstrate both the high and low side of recovery efficiency: the Halfdan, Dan, and Valdemar fields, offshore Denmark (Fig. 2).

High-Side Outcome: Upper Cretaceous-Paleocene Chalk Reservoir, Halfdan Field, Denmark. The Halfdan Field produces oil from a water-wet chalk reservoir. Multiple acid fractures are induced in the producers to maximize productivity, whereas fractures in the injectors are induced by high-rate water injection to increase injectivity, enhance sweep geometry, and achieve voidage replacement (Lafond et al. 2010). Early producers typically suffered from lift problems owing to a combination of low solution-gas/oil ratio and water-cuts of ~20 to 40%. These problems were alleviated by pressure support from adjacent injectors within a year of injection startup. Selective completions provided control of individual production and injection zones, while preventing early water breakthrough and allowing control of water injection distribution. Production peaked at 106,846 BOPD in 2005 before falling gradually to 41,095 BOPD in 2018 when the field had produced 502 MMBO or 31% of STOIIP (Fig. 5a). Successful implementation of high-rate water injection, horizontal drilling, and acid stimulation led to an estimated ultimate recovery factor of 38%.

Mid-case Outcome: Upper Cretaceous-Paleocene Chalk Reservoir, Dan Field, Denmark. The Dan Field produces oil from a water-wet chalk reservoir. During 1987-1990, six >2,500 ft-long horizontal wells were drilled and stimulated with multiple sand-propped fractures (Larsen et al. 1997). Water was injected at high rates and above fracture-propagation pressure, creating fractures up to 4,000 ft long and 200-400 ft high. The hydraulically fractured horizontal wells showed an average fourfold production increase compared to the conventional producers. Hydraulic fracturing of horizontal wells coupled with implementation of seawater injection into deviated wells led to a significant increase in oil production during 1987–1997 (Fig. 5b). Selective completions were used to isolate individual fractures and control the injection rate. From 1997 onward, drilling of high-rate horizontal water injectors caused a marked increase in production, which reached a peak of 118,536 BOPD in 2000. Despite further drilling of two or three horizontal wells per year, production declined steadily thereafter to 20,000 BOPD with an average water-cut of 89% in 2018. Successful implementation of advanced drilling and completion technologies and effective water injection led to an estimated ultimate recovery factor of 28%.

Low-Side Outcome: Lower Cretaceous Chalk Reservoir, Valdemar Field, Denmark. The Valdemar Field produces oil from a mixed-wettability chalk reservoir. Production through four horizontal wells was mostly <3,000 BOPD, but a long horizontal well drilled in 2001 increased production to 8,435 BOPD with a water-cut of 40% by 2004. An additional 15 long horizontal wells subsequently increased production dramatically, peaking at 24,298 BOPD with a water-cut of 36.5% in 2009 (Fig. 5c). Owing to the low reservoir permeability, the wells have been hydraulically fractured (Navarro and Heer 2014). A typical horizontal well has a ~10,000 ft-long lateral section and is completed with 12–16 sand-propped fracture stages spaced ~650 ft apart, designed to connect the full reservoir thickness. In 2010, oil rates fell sharply to an average of 15,662 BOPD with a water-cut of 57%. Despite the drilling of two more horizontal producers, production continued to decline, reaching 11,168 BOPD with a water-cut of 52% in 2018 from 21 active producers. By the end of 2018, the field had produced 86.3 MMBO, representing 12% of STOIIP. Owing to the mixed wettability of the reservoir, water injection at Valdemar would likely be slow and ineffective. Poor control of water production and lack of effective secondary recovery programs led to an estimated ultimate recovery factor of only 14%. Recent numerical modelling indicates that up to ~83 MMBO could be recovered using continuous lean gas injection, resulting in incremental recovery of 11.5% (Suicmez 2019).