Alusta, Gamal Abdalla (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University) | Collins, Ian Ralph (BP Exploration) | Fennema, Julian (Heriot-Watt University) | Armih, Khari (Heriot-Watt University)
This study has focused on the development of a method to test the economic viability of Enhanced Oil Recovery (EOR) versus infill well drilling where the challenge is to compare polymer flooding scenarios with infill well drilling scenarios, not just based on incremental recovery, but on Net Present Value as well.
In a previous publication (Alusta et al., 2011, SPE143300) the method was developed to address polymer flooding, but it can be modified to suit any other EOR methods. The method has been applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process.
The method was then applied and tested (Alusta et al., 2012, SPE150454) with varied operational and economic parameters to investigate the impact in delaying the start of polymer flooding to identify whether it is better to start polymer flooding earlier or later in the life of the project. Consideration was also given to the optimum polymer concentration, and the impact that factors such as oil price and polymer cost have on this decision. Due to the large number of combined reservoir engineering and economic scenarios, Monte Carlo Simulation and advanced analysis of large data sets and the resulting probability distributions had to be developed.
In this paper the methodology is applied to an offshore field where the choice has already been made to drill infill wells, but where we test the robustness of the method against a conventional decision making process for which there is historical data. We do this by performing calculations that compare the infill well scenario chosen with a range of polymer flooding scenarios that could have been selected instead, to identify whether or not the choice to drill infill wells was indeed the optimum choice from an economic perspective.
We conclude from all the reservoir simulations and subsequent economic calculations that the decision to drill infill wells was indeed the optimum choice from an economic perspective.
Desai, Sameer Feisal (Kuwait Oil Company) | Bora, Mir Alam Shah (Kuwait Oil Company) | Al-Matar, Dawood (Kuwait Oil Company) | Rane, Nitin Mansing (Kuwait Oil Company) | Al-Motairy, Salem N. (Kuwait Oil Company) | Saleh, Batoul (Kuwait Oil Company) | Al-Naser, Mariam H.
Greater Burgan Field accounts for most of the oil produced in Kuwait. Discovered in 1938, commercial production from this giant field commenced in 1946 accelerating rapidly to a peak of nearly 3 MMBOPD in 1972. The Burgan structure is an anticlinal dome with numerous faults. The main producing reservoirs are sandstones of Cretaceous age. Four major sandstone horizons within the gross productive section account for most of the current and cumulative production. The 3SM is the main contributory sand which is much thicker than the others. A strong natural water drive maintains reservoir pressure.
The compartmentalization of the main reservoir sands by faults, combined with high production rates, resulted in water incursion problems since the early seventies and made worse by uncontrolled flow from wells sabotaged during the Iraqi invasion. As the 3SM reservoir gets further depleted, water encroachment studies reveal that there is a differential rate of rise in OWC in the massive sand implying un-even sweep. This has created uncertainties in the remaining oil column in flank areas of the field for placement of infill well locations.
This paper presents a methodology applied to successfully identify infill well locations in flank areas of Burgan field. The behavior of faults and rise in water in different compartments were analyzed utilizing seismic surveys, pressure buildup tests and PNC log data combining with production history. Based on the analysis minor faults were characterized and mapped which led to identification of unswept areas where new well locations were proposed. Gross pay found in three new infill wells drilled have been very encouraging.
The process leading to identification of these successful well locations is discussed in length. More infill locations and well intervention opportunities are being identified by using this methodology with increased surveillance to further enhance production from this field.
Gupta, Jugal (Exxon Mobil Corporation) | Zielonka, Matias (Exxon Mobil Corporation) | Albert, Richard Alan (ExxonMobil Upstream Research Co.) | El-Rabaa, Abdelwadood M. (Exxon Mobil Corporation) | Burnham, Heather Anne (XTO Energy) | Choi, Nancy Hyangsil (ExxonMobil Upstream Research Co.)
Fracture nucleation and propagation are controlled by in-situ stresses, fracture treatment design, presence of existing fractures (natural or induced), and geological history. In addition, production driven depletion and offset completions may alter stresses and hence fracture growth. For unconventional oil and gas assets the complexity resulting from the interplay of fracture characteristics, pressure depletion, and stress distribution on well performance remains one of the foremost hurdles in their optimal development, impacting infill well and refracturing programs.
To this end, ExxonMobil has undertaken a multi-disciplinary approach that integrates fracture characteristics, reservoir production, and evolution of the stress field to design and optimize developments of unconventional assets. In this approach, fracture modeling and advanced rate transient techniques are employed to constrain fracture geometry and depletion characteristics of existing wells. This knowledge is used in finite element geomechanical modeling (coupling stresses and fluid flow) to predict fracture orientation in nearby wells.
In this paper, an integrated methodology is described using case studies for two shale gas pads. The study reveals a strong connection between reservoir depletion behavior and the spatial and temporal distribution of stresses. These models predict that principal stresses are influenced far beyond the drainage area of a horizontal well and hence play a critical role in fracture orientation and performance of neighboring wells. Strategies for manipulating stresses were evaluated to control fracture propagation by injecting, shutting-in, and producing offset wells. Collective interpretation of completion, reservoir depletion and changes in stresses explained varying performances of wells and enabled evaluation of infill potential on the pad. This workflow can be used to develop strategies for (1) optimal infill design, (2) controlling propagation of fractures in new neighboring wells, and (3) refracturing of existing wells.
Advances in drilling and fracturing technologies in Woodford Shale have attracted the operators to drill horizontal wells with long laterals (up to 5,000 ft), and to fracture using multiple stages (up to 22) using large amounts of slickwater and sand. It has been observed that exploitation of shale plays relies on the ability to contact as much of the reservoir as possible using fracturing techniques by creating a network of interconnecting fractures between laterals placed as close as 660 ft apart. As the spacing gets closer, the operators have a vested interest in knowing the optimal spacing of infill wells. Ideally, an infill well should have as little interference with the existing wells as possible.
In this paper, we examine fracture data, and daily gas and water production data of 179 horizontal gas wells over five years in the Arkoma Basin to quantify the impact of interference between wells on their performance. We quantify the lost gas production from the surrounding wells; calculate the probability of interference as a function of distance and age of the surrounding well; determine the preferential direction of interference, and develop a new measure of spacing to understand the relationship between performance of the well and its surrounding wells. Finally, we provide recommendations regarding the spacing of infill wells.