As a consequence of the prolonged low oil price, resource portfolios are being evaluated on stringent capital efficiency criteria; minimising financial risk; and maximising return on investment.
This has naturally resulted in prioritising projects with high value investment ratios, rather than large capital intensive (albeit high absolute net present value) projects; favouring infill, small brownfield and tie-back projects to existing infrastructure over marginal greenfield projects. Notwithstanding this, many operators are keen to monetise small, stranded, marginal oil resources as it is believed that successful development of these resources would offer significant potential; moreover, in many cases government authorities are keen to see such resources developed and are linking future exploration licence awards to successful monetisation of these small pools.
This article discusses the particular challenges of the disposition of gas co-produced from stranded oil and small marginal pools. This is the first article from io on this subject which aims to frame the problem with a second to follow on technology to enable gas monetisation.
Significant Monetisation Potential
Within the UK Continental Shelf (UKCS) alone, the Oil and Gas Authority (OGA) and operators therein are seeking to unlock the potential of some 350 unsanctioned discoveries containing more than 3 billion boe [REF 1] in total. These are small fields containing resources of less than 50 million boe each, most are located close to existing infrastructure; however, some are stranded.
Data from Global Data and other sources demonstrates similar potential on a global scale for offshore fields. The bubble map in Figure A [REF 2] illustrates the large number of offshore conventional small pools (less than 50 million boe recoverable). Of the total number of conventional offshore discovered resources, the number of small pools is approximately 75%. There are also many stranded oil and small marginal pools onshore in remote locations with very limited infrastructure and so the considerations discussed here apply to these resources too.
Fig A. The monetisation potential of conventional small offshore pools
Notwithstanding this huge potential, many operators are grappling with how to monetise these fields. The industry has responded with innovative offerings, for instance, maximising the re-use of assets with the concept of the Versatile Production Unit (VPU) such as NOV’s Honeybee and the Amplus VPU. This concept is not new; BP’s Seillean (Gaelic for bee) SWOPS (Single Well Oil Production Ship) was designed in the late 80’s and operating in the 90’s. Despite this, few small pool and stranded oil projects make it to sanction and remain undeveloped.
Few stranded oil projects make it to sanction - why is this?
Clearly the economics of small oil pools are challenged and often fail because of the cost of gas disposition. Unfortunately, it is io’s experience that this issue is often treated as an afterthought whereby dealing with this by-product through consumption, monetisation and/or disposal is often deferred or even overlooked with broad assumptions made to the detriment of the project and its development economics. This often results in wasted effort focussing on minimising facilities CAPEX in regard of the “gas problem”. The industry paradigm seems to be: burn the gas to create electricity and process heat for internal use or assume it can be injected. This article will discuss why gas disposition is a key enabler or disabler for small pools and should be weighed and considered much earlier in the evaluation process.
Figure B demonstrates that in terms of associated gas, the volumes generated from low to moderate oil production rates of 10,000 to 40,000 bopd appear to be modest (2 MMscfd to 14 MMscfd) using gas to oil ratios (GORs) ranging between 50 to 350 scf/bbl which is often perceived to be manageable. However, when the gas is converted into energy released and electrical power, the magnitude of available power is “revealed” and often far exceeds the requirements of the facilities. In this example, the electrical power is estimated using a modest efficiency of 30% and assuming a simple cycle gas turbine power generator. Clearly the issue of gas disposition is proportional to the GOR; developments with lower GORs (50 to 150 scf/bbl) tend to have a greater chance of success.
Fig B. The indicative impact of GOR on gas handling requirements
This problem is brought into context when life of field requirements are considered. To illustrate this, a hypothetical profile (Figure C) has been generated with a peak oil production of 19,000 bopd (45 mmbo recovery) at two different GORs of 120 and 350 scf/bbl. Against these profiles, indicative electrical power requirements have been estimated for an offshore standalone facility assuming two producers, two water injectors, ESPs and gas injection compression.
Fig C. The indicative impact of GOR on hypothetical profiles and their life of field power requirements
Both profiles indicate an early period when associated gas volumes exceed fuel gas requirements; in later years, the facilities are gas deficient and require a supplementary fuel such as diesel. Once the facilities become fuel gas deficient, 40% and 20% of recoverables still remain at GORs of 150 scf/bbl and 350 scf/bbl respectively.
The lower GOR magnifies the issues associated with gas deficiency such as the high operating costs of importing diesel. The higher GOR magnifies the issues associated with excess gas which will be discussed later in this article. It is advisable to perform a similar exercise for life of field heat requirements to understand the impact on major heat users.
Two of the electrical power users that contribute to the power balance in Figure C are seawater lift pumps and water injection pumps. Figure D demonstrates that these duties are relatively modest. Other users are expected to be ESPs typically ranging 250-750 kW each; a FPSO power consumption for lighting, ballasting, HVAC is expected to be approximately 2 MW to 3 MW continuous load.
Fig D. Indicative Power Requirements for seawater lift and water injection pumping
can excess associated gas be avoided?
In the early field development phase, it is prudent to integrate with subsurface and drilling to determine if there is opportunity to prioritise on drilling low GOR wells first and delaying high GOR wells. There may need to be a trade-off between de-risking (targeting certain fields or zones earlier for instance) against value. Nevertheless, this approach would certainly help to balance out the gas requirements for the facilities.
gas injection for disposal
After power generation, the next most common gas disposition solution tends to be gas injection for disposal (and potentially recovery later in field life). It should be noted that gas lift does not dispose of associated gas as these flows recycle between the facilities and subsurface (although gas lift can be a large power user).
From a subsurface viewpoint, the most likely and easiest place to inject is in to the producing formation itself. However, this is not without challenges or risks. Typically, small oil pools have reservoir thicknesses with relatively thin oil columns and oil producing wells located towards the top of the reservoir. This is intrinsically linked to the difficulty in locating gas injection wells too close to the oil producers which could result in the injection gas breaking through prematurely at the oil producers causing high GOR production. The GOR may rise quickly in later years and the problem fundamentally remains. An alternative location for gas injection is a local aquifer, however this brings uncertainty in terms of suitability, identification thereof and diminishes the potential to recover. The potential to recover gas in later years from a producing formation is highly dependent on subsurface complexity and geology. Additionally, the subsurface team need to address the viability of injecting these gas volumes. A 45 mmbo pool would generate cumulative gas volumes ranging from 5 to 15 bcf over the life of field (using a GOR of 120 to 350 scf/bbl).
The costs of gas injection are not trivial. The drilling cost for a single disposal well would be in the range of $25-30 million; well reliability might result in requiring two disposal wells. From a facilities perspective, gas injection would be a requirement in the early years. This increases the CAPEX to first oil, thus eroding the economics and would only be in service for a relatively short period. The additional costs to be borne include subsea architecture, topsides gas injection compression and treatment which are indicative of $75 – 90 million (excluding operator’s costs). These costs increase quickly for developments designed for deep water; higher gas injection pressures; requiring H2S or CO2 removal and so on. Note too that conceptual decisions are often strongly influenced by non-technical aspects, for instance, stakeholders may object to gas injection for disposal or there may be restrictions to the quantities injected without recovery.
gas to flare
Past projects have demonstrated that small pools of oil can be unlocked in an economic way. Seillean SWOPS maximised use of the associated gas for internal power generation and sent any surplus gas to flare. During periods of gas deficiency, diesel driven generators provided the power supplemented by gas turbine driven generators operating on diesel oil. However, stricter flaring restrictions are being imposed on current and future projects. For example, flaring on the Norwegian continental shelf is prohibited except for safety reasons [REF 3]. Permits are granted on a case by case basis on technical and safety grounds. This long-standing aspiration has stimulated R&D in areas such as gas to liquids (GTLs) [REF 4]. The real outcome was a reduction in flaring by improving field design and operations. The issue still remains for well testing and extended well testing with temporary flowlines being too expensive to lay between existing infrastructure and distant remote fields.
conclusion: thinking with the “end in mind”
It is io’s belief that the gas disposal issue and its impact on development economics for marginal or small pools (even more major developments) should be attended to much earlier on in the commerciality assessments. Moreover owners/operators should prioritise fields with low GORs of 50 to 150 scf/bbl as these developments will have a greater chance of success.
To find a solution balancing the techno-economic interdependencies requires a multidisciplinary approach, bringing together reservoir & subsurface, drilling, subsea, marine, facilities, economic modelling, commercial and strategy. By considering challenges of this nature with a systems thinking approach, io leverages an integrated, multi-disciplinary team with wide and deep domain expertise. In this way, the interdependencies between each aspect of the problem may be captured to determine the most viable solution. This integrated and holistic approach also applies to developments with high GORs and higher gas rates which are more suited for gas monetisation and will be addressed in a future io article.
Fig E. io’s integrated approach
 E&P magazine Feb 2017www.epmag.com/marginal-fields-offer-last-opportunity-north-sea-oil-1463436
 Global Data and io data, 2018