Effect Of Inverted Injection Patterns On Performance Of Thin Oil Rim Reservoirs (Case Study Of Four And Five Spot Patterns)

Description

ABSTRACT

Multilateral wells have been documented to afford better production performance than vertical wells in primary oil recovery processes especially in thin reservoirs. However, little is known about how multilaterals perform relative to vertical wells in water-injection secondary recovery processes, and how the configuration and pattern of arrangement of these multilaterals affect their performance. The injection pattern for an individual field or part of a field is based on the location of existing wells, reservoir size and shape, cost of new wells and the recovery increase associated with various injection patterns. The flood pattern can be altered during the life of a field to change the direction of flow in a reservoir with the intent of contacting unswept oil. It is common to reduce the pattern size by infill drilling, which improves oil recovery by increasing reservoir continuity between injectors and producers.  In this work, the impact of using inverted injection patterns on thin oil rim reservoirs was studied.

Nomenclatures
Boi	Initial formation volume factor, bbl/stb
ho	Oil rim thickness, ft
i, j	Integer increments
kh	Horizontal permeability, md
kv	Vertical permeability, md
M	Ratio of gas cap pore volume to oil rim pore volume (m-factor )
Npw	Ultimate oil recovery per well, MMstb
perfpos	Vertical good perforation position within the oil rim relative tothe gas-oil contact at 0 and the oil-water contact at 1
qgi	Gas cap offtake, %
qoi	Oil rim offtake, %
RF	Oil recovery factor, %
Rng	Net-to-gross ratio
reD	Ratio of aquifer radius to total reservoir radius
Sor	Residual oil saturation
Swc	Connate water saturation
Greek Symbols
Θ	Reservoir Dip, degrees
µ	Oil viscosity, cp
Ø	Effective porosity
FGIIP	Free Gas Initially in Place
GOR	Gas Oil Ratio
RE	Recovery Efficiency

 

 

1.0                                                         INTRODUCTION

1.1                                           BACKGROUND OF THE STUDY

In general, any saturated oil accumulation in a porous medium underlain by an aquifer is an oil-rim reservoir. More specifically, an oil-rim reservoir is characterized by an oil zone overlain by a relatively large and active gas cap while, at the same time, underlain by a relatively large and active aquifer. Depending on the geometry of the gas cap and aquifer that envelope the oil zone, an oil rim can be of a doughnut or pan-cake type. Because the dynamics of gas cap and aquifer in the doughnut and pan-cake oil-rim configurations are not necessarily the same, the evaluation and management of oil-rim reservoirs are complex, computationally intensive and less straightforward.

As a result of the active gas cap and aquifer, the exploitation of oil rims is often associated with complex production problems, which are attributed to an early breakthrough of gas and/or water. Most oil-rim developments are bedevilled by gas and water coning, both of which are detrimental to well productivity and ultimate recovery. The early and sustained production of these unwanted associated fluids increases the operating expenses related to handling gas and water produced per unit volume of oil recovered, hence eroding project value. Because coning rates are usually below economic thresholds, the strategy of limiting oil offtake below gas and water coning rates has not recorded significant success in practice.

From a development planning standpoint, there are always questions about the most appropriate development concept and well type for a given oil-rim reservoir. Another common puzzle is the best timing to commence dedicated gas development by blowing down the remaining gas cap after the oil resources might have been exploited to some techno-economic limits. Recognizing that both oil and gas are prospective revenue sources, it is not uncommon for the developers of oil-rim reservoirs to have extensive debates on the following alternative development options at early stages: (1) develop oil first, and the gas later; (2) develop only the gas, essentially ignoring the oil; (3) develop both oil and gas concurrently, but produce gas intermittently; and (4) develop and produce both oil and gas concurrently. The arguments and counter-arguments for these options are diverse and tend to vary from one case to the other, underscoring the need to improve the current body of knowledge on this subject for better decision-making (Obidike et al. 2019)

Maximizing the recovery of either or both oil and gas in an oil-rim reservoir is clearly an optimization problem. In searching for an optimum solution, the rigorous evaluation of the various development options often requires extensive reservoir simulation studies. This optimization problem entails multiple variables, which include geologic, engineering, economic, regulatory and operational factors These variables usually exhibit varied dependencies, thereby complicating the problem of selecting the most appropriate combination of well type, development concepts and production constraints. The solution to this problem is computationally intensive, with the attendant delay in decision-making, yet it does not guarantee the uniqueness and optimality of the outcome and recommendations.

To partly address the foregoing challenge of time-consuming evaluation and its negative impacts on turn-around time for business decisions, the investigation of oil-rim reservoirs often entails the use of simple screening methods to narrow the search space, as against exploring the large solution space. For this purpose, different screening techniques, which can broadly be classified as empirical, numerical and analytical, have been published and applied with mixed success The primary objective of these models is to provide simple guidelines on the feasibility of oil-rim exploitation and the appropriate development concept, especially at the early stages of field studies and development planning. A review of some of these models and their relative drawbacks has been documented by other workers (Lawal et al. 2010).

Vo et al. (2000) used performance data from some horizontal wells completed in oil-rim reservoirs in Indonesia to derive a mathematical function relating oil recovery factor (RF) to oil column thickness. Earlier, Irrgang (1994) analysed performance data from some conventional wells completed in a limited number of oil-rim reservoirs in Australia to derive a correlation for estimating oil ultimate recovery (UR) as a function of some petrophysical and fluid properties. None of these empirical methods provides a basis for comparing the effects of different well types, nor can they be used to assess the feasibility of exploiting either the gas cap or maximizing both oil and gas recovery. In addition, these correlations do not provide any clue on either the timing or the sequence for developing the oil and gas resources.

Introducing the idea of expanding mobile energy as the basis for oil recovery, Lawal et al. (2010) derived an expression for estimating oil RF of an oil-rim reservoir. In their work, it was assumed that oil recovery was linearly proportional to the energy expended by the reservoir. They argued that the magnitude of this reservoir drive energy is governed by the pressure–volume work done by an expanding gas cap. However, restricting oil offtake to the gas coning rate, ignoring aquifer drive and non-consideration of possible production acceleration are some drawbacks of their proposition.

With the aid of numerical reservoir simulations, Yeoh (2014) studied the dependencies of oil RF on horizontal permeability, vertical-to-horizontal permeability ratio (i.e. permeability anisotropy), oil viscosity, gas-cap size, aquifer size, well spacing, oil rate and initial oil thickness for a thin oil-rim reservoir. This effort yielded a correlation that relates oil RF to these variables. Among other shortcomings, the work was restricted to oil-only development. In addition, the correlation does not provide guidance for using production acceleration to discriminate between competing development concepts and well types.

John (2017) and then John et al. (2019) used experimental design to create 17 different numerical experiments to study the effects of seven independent variables on oil RF from oil-rim reservoirs. Parameter screening and response-surface methodology were then applied to select the most important variables and establish relationships between them and RF, for three different development concepts vis-à-vis oil-then-gas (OTG), concurrent oil and gas (COG), as well as gas-only development. However, the studies did not consider the oil-only development option, nor did they provide a clear heuristic on when to switch from oil to gas-cap blowdown in the case of an OTG option. Additionally, their use of ultimate oil RF as the objective variable precludes the resulting models from accounting for differences in production acceleration, which is a proxy for economic performance, among the development options.

Following a critical appraisal of previous works on the evaluation and development of oil-rim reservoirs, Obidike et al. (2019a) reported several key findings, including areas of improvement. They noted the lack of consensus on the definition of oil-rim reservoirs, as well as the primary factors that drive the development and management of these resources. More instructive, they queried the general focus on technical factors, at the expense of equally important non-technical factors (commercial and strategic), in the current practices of screening oil-rim reservoirs for exploitation. In line with this thought, Thomas and Bratvold (2015) earlier argued that maximizing the production time of profitable oil at the expense of the associated gas-cap does not necessarily guarantee the return of maximum value from an oil-rim development project. Rather, they advocated for a real-options approach, where the maximum value, hence business decisions, would be driven by expected revenue and cost profiles linked to either or both oil and gas, as well as the timing of their developments. Therefore, we opine that a screening model that is simple, yet incorporating relevant technical and non-technical factors, would be value added to both the theoretical and practical aspects of the assessment, development and management of oil-rim reservoirs.

Considering the limitations of existing methods, we introduce a different approach for screening development concepts for oil-rim reservoirs. A new parameter, consisting of relevant technical and non-technical (economic) factors, is proposed for characterizing the performance of an oil-rim reservoir for different development options and well types. As a further improvement over previous approaches, we employ discounted recovery factor, rather than either absolute recovery factor or ultimate recovery, as the basis for screening. In addition, unlike existing formulations that focus on the recovery of just oil as the hydrocarbon of interest, our new guideline offers the flexibility to consider any of oil, gas or total hydrocarbon as the primary driver for screening the development options for an oil-rim reservoir.

In essence, this paper presents a new technique and workflow that employs basic and readily available rock and fluid properties to identify the optimum development concept(s) in terms of primary hydrocarbon target and, where necessary, the suitable time to commence the conscious exploitation of the secondary hydrocarbon fluid in oil-rim reservoirs. More specifically, clear quantitative guidelines are provided to screen the various oil-rim reservoir development options vis-à-vis oil-only, COG, OTG and, by extension, gas-only (i.e. gas-cap blowdown). Additionally, the new propositions account for the effects of vertical versus horizontal wells and provide quantitative insights into how these well types influence the performances of the aforementioned development options.

The overall aim of this study is to (a) investigate the effect of inverted injection patterns (b) to compare the performance of the system with other types of oil recovery operation.

1.2                                                  PROBLEM STATEMENT

Development of oil rim reservoirs is challenging and could lead to low oil recovery, if multiple determining factors are not well understood, that influences successful field development concept. It requires detailed analysis and development of specific procedures to optimize the oil production from a thin oil rim underlaying gas cap. Few IOR/EOR applications for oil rim development have been reported in the literature so far. This study presents a concept for the optimization of oil production from an oil rim reservoir by inverted injection pattern.

1.3                                                   AIM OF THE PROJECT

The main aim of this work is to study the effect of inverted injection patterns on thin oil rim reservoirs performance and to perform an optimization model by setting an objective function to improve recovery factor and reduce water/gas cut. The latter was run until converging, and the optimal solution was used to perform further IOR/EOR studies.

1.3.2                                                      OBJECTIVES

The project objectives are as follows;

• To setup a model that will enhance oil recovery
• To perform IOR/EOR methods including water/gas flooding/injection and surfactant flooding using inverted five-spot horizontal well pattern, for the application in the selected sector.
• To implement inverted injection pattern to estimate the oil recovery
• To decide whether inverted injection pattern would be most profitable for an oil rim reservoir.
  • SIGNIFICANCE OF THE STUDY

The reasons for the choice of inverted injection pattern reservoir was enumerated for which the cardinal objective is to create more reservoir contact with the wellbore for enhanced productivity and reduction or delay of bottom water cresting or overlying gas cresting for maximum oil recovery (Peng and Yeh, 1995) before Enhanced Oil Recovery (EOR) is adopted as usually the case.

Thus inverted injection pattern serve as a basis for implementing injection schemes in oil rim reservoirs for optimum recovery.

• SCOPE OF STUDY

The scope of this study is to investigate the impact of inverted pattern on the performance and oil recoveries in a thin oil rim reservoir of four and five spot patterns. Thus, this is a predictive work and the intricacies of reservoir traits, behavior and properties are not fully considered as the oil rim model used in the study is already incorporated with these functions.

Injection is an essential part of many modern oilfield development plans. The high costs and often tight economic margins especially in offshore developments require that the chosen waterflood design not only provides an optimum sweep efficiency and reservoir pressure support to maximize the oil production revenue, but also carries an acceptable level of risk in terms of the project costs and technical un- certainties. While enhanced oil recovery has benefited from multilateral well technology in the area of steam assisted gravity drainage (IPIMS), there seems to be reluctance in embracing this technology for the optimization of secondary processes like water injection despite apparent advantages.

•      STUDY AREA

This research study would cover a modified model of a pre occurring oil rim located of four and five spot patterns. Several simulations would be conducted in order to determine the impact of inverted injection pattern on performance of thin oil rim reservoirs.