TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThin oil columns overlain by free gas and underlain by water pose serious challenges for completion and production. For such columns sandwiched between a sizeable gas cap and weak aquifer, gas coning usually limits oil production below commercial rates. For reservoirs with developable oil rim, the strategies of simultaneous oil and gas production as well as gascap blowdown after oil recovery, have been studied and implemented. Where a gas market is available, the choice of strategy is usually dictated by optimisation of reservoir energy and early revenue from gas monetisation. This paper investigates feasibility of intermittent production of the gascap with continuous oil production. A three-dimensional simulation study was performed for a gas-cap driven oil-rim reservoir having the primary objective of producing oil and a secondary objective of making up occasional gas supply shortfalls, the swing gas option. Key factors such as gas offtake rate, offtake frequency and the period to sustain each offtake cycle were examined. Impacts of these factors on oil recovery, total hydrocarbon recovery and project economics were evaluated. While the study indicates feasibility of swing gas production, reservoir and fluid uncertainties are important issues that must be properly managed. For these, adequate reservoir management and production practices are recommended.
The main objective of the Marginal Fields Programme (MFP) initiated by the Federal Government is to enhance indigenous participation in the exploration and production of hydrocarbon in the Niger Delta. Under the MFP initiative, backed by the Petroleum (Amendment) Decree Act No. 23 of 1996, holders of Oil Mining License (OML) were required to farm-out fields that have remained unproduced for at least 10 years to indigenous Nigerian Exploration & Production (E&P) companies. Majority, if not all, of these farmed-out fields are classified as marginal fields. A marginal field is defined as "a field that may not produce enough net income to make it worth developing at a given time; should technical or economic conditions change, such a field may become commercial". Thus the task facing the E&P companies that were given the farmed-out fields is how to make their development attractive economically i.e. produce enough net income. Changing the technical and/or economic conditions of these marginal fields is made challenging by virtue of the very limited technical data available. It is common knowledge that much attention has not been given to these fields in the past and is the main reason why they have remained unproduced. Leveraging on the large footprint of the Shell Petroleum Development Company (SPDC) across the Niger Delta and making use of her PVT database for sampled, analysed and/or producing fields, the Niger Delta region was sub-divided into geological units based on similarity in observed PVT parameters. With the work done and presented in this paper, knowing the geological location of any marginal field in the Niger Delta is enough to fairly estimate its basic PVT properties. The paper goes further to show, using a case study through a dynamic simulation model built for a marginal field, that previous PVT estimations, recoveries and development economics for the case study marginal field were pessimistic.
With increasing drive to account for associated gas, it has become necessary to have a reliable technique for extrapolating gas-oil ratio (GOR), commonly used to quantify gas produced with the oil. While there have been significant improvements in the number and quality of techniques available for analysing oil-rate data, GOR prediction has not advanced appreciably. In this paper, a systematic methodology developed on the basis of a new internally consistent GOR model, is presented. Applicability is demonstrated with a field example, which also illustrates its use for estimating recoverable volume of associated gas during oil decline. The good agreement of the results with field data affirms the accuracy of this methodology. While emphasising the importance of consistent data, it is concluded that reservoir and fluid mechanics, as well as operational procedures, are other important considerations when extrapolating GOR. Practical application of this work includes surveillance and management of oil well, reservoir and field. Introduction Several mature oil fields (reservoirs) perform below expectation because of excessive gas production which, in the absence of a gas market, creates serious environmental concerns, sub-optimal performance of surface facilities, and increased operating cost, leaving large oil reserves unproduced. Managing these requires reliable forecasts of the associated gas (AG). In practice, AG is estimated from the producing gas-oil ratio (GOR) and oil production. Traditionally, industry's interest in GOR was limited to its use as a well/reservoir performance indicator. However, with increasing concerns for gas monetisation and environmental performance, the industry is being challenged to improve GOR modelling. One of such challenges is posed by the United Nations' Clean Development Mechanism (CDM) under the Kyoto Protocol(1). The CDM rewards improved environmental performance. For projects recovering and utilising AG that would otherwise be flared/vented, reliable AG (GOR) forecast is a key input for assessment of environmental additionality. The analysis of performance trends (decline curves) of oil and gas production data is widely used for modelling and forecasting. Although traditional techniques implicitly assume constant flowing bottomhole pressure (FBHP)(2–6), with continuous drop of production rate with time, there are modern techniques that correct for FBHP dynamics(7–8). The ideal approach is that which respects reservoir, fluid and wellbore dynamics in predicting production performance.
Well testing during the drilling of a well using a Drill Stem Test (DST) tool is a well-established practice in the oil and gas industry. As the name suggests the well test is conducted using the drill stem with the DST tool replacing the drill bit. It is done in open or cased hole and the objective is to measure the pressure, permeability and productivity of the zone of interest. It also gives a measure of the damage done to the formation during the drilling process.In the case of an oil reservoir oil is produced to surface during the DST operation and either collected in tanks or flared together with the associated gas. In the case of a gas-only reservoir the gas produced to surface is flared.Some of the issues of carrying out a DST test are the high costs involved, limitations in acquiring detailed zone specific information instead of averaging over the well test length and the potentially negative impact on the environment from hydrocarbon flaring. It is to overcome these challenges that the industry looked for alternative well test approaches that can be more efficiently undertaken during drilling operations such as the Wireline Formation Test (WFT), also known as a mini-DST.A mini-DST well test is carried out using a wireline tool and is conducted in open-hole. The well test involves isolating a zone of interest using packers with pressure and hydrocarbon flow rate readings captured using a single probe, a dual probe or a combination of single and dual probes. Unlike the DST it can be done over multiple zones, isolating one zone at a time and has an added advantage that all fluid flow takes place down-hole.In reservoir intervals with good permeabilities and high production rates, the relatively high mobility of gas compared to oil will result in turbulent flow being observed in the wellbore thereby introducing 'noise' that will mask the sensing of pressure transients by the probe. This is not the case in mini-DST test as the production rates are quite low already. However, for a gas reservoir it is sensitive to the permeability-thickness (kh) product in the zone of interest, since higher kh and lower gas rates can result in a very small drawdown. Therefore pressure gauge sensitivity becomes a significant factor in the well test design for a mini-DST. With a typical gauge resolution of ca. 0.01 units there is, therefore, an inherent constraint to targeting primarily low kh flow zones. This can result in a trade-off when selecting reservoir units to test based on their permeability (k) and thickness (h).This paper looks at some of the issues to be considered in the design and operation of a mini-DST well test for a gas reservoir and highlights key benefits that can be derived. It further discusses some of the operational challenges encountered during a case study.
The York gas field is located in the Southern North Sea (SNS) area of the United Kingdom Continental Shelf (UKCS). Structurally the field is interpreted as having a good number of intra-faults. Of particular interest to this paper is the intra-fault located south-west of the field. Due to the presence of this fault there are two separate crests in the southern area of the field. Each of these two crests was targeted by a horizontal well in the initial development plan of the field. A third horizontal well was to be drilled and completed in the eastern flank of the field. Recent subsurface studies involving petrophysical, geological and reservoir engineering re-interpretation and analysis carried out in the field confirmed the well count, but not the well type, required for development of the field as compared to previous development plan. Furthermore, it was established that by drilling and completing across the aforementioned south-western intra-fault, instead of avoiding it as done in the previous development plan, the total well count for developing the field is reduced by one. Two optimal development scenarios, both having similar recoveries, have been identified for the development of the field. Option 1 has two development wells and requires drilling and completing across an intra-fault. Option 2 requires three development wells and no across fault drilling/completion. Economic analysis of the two development options shows that option 1 has better economics indices. Thus, though option 1 is deemed challenging because it requires drilling/completing across a fault the cost savings to be realised from implementing a two well development, instead of the three wells required in option 2, makes it more attractive, nevertheless. The paper presents the basis and merits of adopting option 1 as the preferred development option for the field. It further discusses the challenges and issues associated with drilling/completing across a fault and way-forward plans to be adopted for a successful implementation of the option 1 development plan. The paper concludes by presenting option 2 as a contingency option to be implemented in the event that option 1 is not successful with regards to drilling/completing across the aforementioned intra-fault.
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