Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
The global economy continues its journey of evolution and progression driven by industrialism as its primary force. With such a fast pace of development and recovery from several recessions over a number of years, dependency on energy sources became inevitable to satisfy the rising demand. This paper represents a proposed global energy price model that has the flexibility of modeling the energy price, using data from specific regions of the world, as well as the global energy pricing equation. The ANM (Alternate Novel Model) is presented here.
The model focuses mainly on oil price modeling, since oil accounts for more than 84% of the current world energy supply. The model duration is 50 years; starting from 1980 to 2030, model matching period from 1980 to 2011, and the prediction period is from 2012to 2030.
The modeling approach used in ANM adopts weighted averaging of individual factors and it relies on line regression technique. Therefore, future trends are being predicted based on the cyclic nature of the market and historical data "the future is reflection of the past??. ANM can then preduct the future oil prices, depending on the factors and variables that have been placed in the process for the output results.
The paper aims to propose a reliable model that accounts for most governing factors in the global energy pricing equation. All steps followed and assumptions made will be discussed in detailto clarify the working mechanism for this model and pave the road for any future modifications.
The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test design and new wells' location identification. Currently, the primary method of estimating the well drainage radius is buildup tests and their subsequent well test analysis. Such buildup tests are conducted using wireline-run quartz gauges for an extended well shut-in period resulting in deferred production and risky operations.
A calculation method for predicting well/reservoir drainage pressure and radius is proposed based on single-downhole pressure gauge, flowing well parameters and PVT data. The proposed method uses a simple approach and applies established well testing equations on the flowing pressure and rates of a well to estimate its drainage parameters. This method of estimation is therefore not only desirable, but also necessary to eliminate shutting-in producing wells for extended periods; in addition to avoiding the cost and risk associated with the wireline operations. The results of this calculation method has been confirmed against measured downhole, shut-in pressure using wireline run gauges as well as dual gauge completed wells in addition to estimated well parameters from buildup tests.
This paper covers the procedure of the real-time estimation of the well/reservoir drainage pressure and radius in addition to an error estimation method between the measured and calculated parameters. Furthermore, the paper shows the value, applicability and validity of this technique through multiple examples.
Fracture ballooning usually occurs in naturally fractured reservoirs and is often mistakenly regarded as an influx of formation fluid, which may lead to misdiagnosed results in costly operations. In order to treat this phenomenon and to distinguish it from conventional losses or kicks, several mechanisms and models have been developed. Among these mechanisms under which borehole ballooning in naturally fractured reservoirs take place, opening/closing of natural fractures plays a dominant role. In this study a mathematical model is developed for mud invasion through an arbitrarily inclined, deformable, rectangular fracture with a limited extension. A governing equation is derived based on equations of change and lubrication approximation theory (Reynolds’s Equation). The equation is then solved numerically using finite difference method. Considering an exponential pressure-aperture deformation law and a yield-power-law fluid rheology has made this model more general and much closer to the reality than the previous ones. Describing fluid rheology with yield-power-law model makes the governing equation a versatile model because it includes various types of drilling mud rheology, i.e., Newtonian fluids, Bingham-plastic fluids, power-law, and yield-power-law rheological models. Sensitivity analysis on some parameters related to the physical properties of the fracture shows how fracture extension, aspect ratio and length, and location of wellbore can influence fracture ballooning. The proposed model can also be useful for minimizing the amount of mud loss by understanding the effect of fracture mechanical parameters on the ballooning, and for predicting rate of mud loss at different formation pressures.
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.
In recent times the topic of well barrier integrity has become increasingly salient. Within the well completion arena, there have traditionally been two main alternatives for barrier plugs used for packer setting or temporary well abandonment; these are the metallic flapper or ball type isolation plugs. This paper describes the evolution of an innovative glass type barrier plug from its first appearance in the oilfield in 2004, to the deployment of third generation prototype systems into wells in the North Sea today.
Traditional ball or flapper type plug systems need to operate in two states: open and closed. This functionality typically necessitates the use of dynamic seals, which also have to compensate for the pressure differential applied across the plug. Plugs built in this manner can be prone to malfunctions in the dynamic seals and have limitations as to the pressure differentials that can be applied to them when opening. Additionally as the balls or flappers themselves are traditionally manufactured using metallic alloys, in the event that a plug fails to open the only alternative is milling, which if successful, will still leave a restriction in the well limiting options for future well interventions.
Glass barrier plugs have to operate in two slightly different states, solid or shattered. When the plug is run in hole the glass is in a solid state with pressure integrity maintained using static elastomeric seals. Once well operations have progressed to the stage when the plug needs to be opened, a preinstalled trip saver can be activated which would shatter the glass and open well communication. Operating in this manner avoids the use of dynamic seals thereby increasing plug reliability. Other major advantages are that the differential pressure applied across the plug when opening has no effect on the plugs functionality and since the plug is made out of glass, in the event of a trip saver malfunction the plug can be opened using a shoot down tool, a spear, or milled within approximately 10 minutes using a wireline tractor (Welltec, 2011) leaving a full bore ID for future well interventions.
This paper describes how BP Norway and TCO used the lessons learned from two generations of Glass Barrier Plugs (GBPs) to develop a system with increased debris tolerance, improved redundancy and a larger inner diameter.
The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization.
The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations.
This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans.
The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations.
The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.
At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
The North Kuwait Jurassic Gas (NKJG) reservoirs are currently under development by KOC with assistance from Shell under an Enhanced Technical Services Agreement (ETSA). The fractured carbonate reservoirs contain gas condensate and volatile oil at pressures up to 11,500 psi with 2.5% H2S and 1.5% CO2. This paper describes the planning and implementation of a Well Integrity Management System (WIMS) that allows the safe management of the wells that are being drilled in this hazardous environment.
The wells are designed and constructed in accordance with KOC standards and on transfer of ownership from Deep Drilling Group to Production Services Group have their integrity managed under WIMS. The system is a structured process, relating the frequency and extent of routine monitoring and testing to the particular risks associated with the wells. Compliance with WIMS requirements are routinely reported so that all are aware of the current state of well integrity. WIMS is initially managed through simple spreadsheets and during 2012 is being integrated into KOC's Digital Field infrastructure.
Initially, WIMS has been applied to the range of wells ‘owned' by Production Services Group and tests currently carried out by Well Surveillance Group under PSG's direction. In order to realise the full assurance of safe operation the scope of WIMS application is being extended to the full well population, including suspended wells, and the full range of tests required.
Implementation of WIMS will allow KOC (NKJG) to be able to state that ‘our wells are safe and we know it'.
Carbonate formations are very complex in their pore structure and exhibit a wide variety of pore classes. Pore classes such as interparticle porosity, moldic porosity, vuggy porosity, intercrystalline porosity, and microporosity. Understanding the role of pore class on the performance of emulsified acid treatment and characterizing the physics of the flow inside is the objective of our study.
The study was performed using vuggy dolomite cores that represent mainly the vuggy porosity dominated structure, while the homogenous cores represent the intercrystalline pore structure. Core flood runs were conducted on 6 x 1.5 in. cores using emulsified acid formulated at 1 vol% emulsifier and 0.7 acid volume fraction. The objective of this set of experiments is to determine the acid pore volume to breakthrough for each carbonate pore class at different injection rates.
In this paper, a novel approach to interpret the core flood run results using thin section observations, tracer experiments, SEM, and resistivity measurements will be presented. Thin section observations provide means to study the vugs size and their distribution, connectivity, and explain the contribution of the pore class in the acid propagation. Relating the rotating disk experiments of emulsified acid with dolomite to our core flood run results will be also conducted in order.
The acid pore volumes to breakthrough for vuggy porosity dominated rocks were observed to be much lower than that for homogenous carbonates (intercrystalline pore structure). Also, the wormhole dissolution pattern was found to be significantly different in vuggy rocks than that in homogenous ones. Comparison of thin section observations, tracer results and the core flood runs results indicates that the vugs are distributed in a manner that creates a preferential flow path which can cause a rapid acid breakthrough and effective wormholing than those with a uniform pore structure. Rotating disk experiment results, demonstrating that the reaction of emulsified acid with dolomite is much lower than that with calcite, showed that the reaction kinetics played a role in determining the wormhole pattern.