As reservoirs mature, subsurface flow complexity and surface production operation challenges increase. This brings the necessity of making capital-intensive decisions to sustain or increase reservoir potential in an optimum way. However, subsurface uncertainties affect decision success. Reservoir surveillance, a process that involves data acquisition, validation, analysis, integration opportunity generation and execution, can mitigate the outcome of such decisions in the presence of uncertainties. Although Value of Information (VOI) is a well-known process for justifying data acquisition, engineers struggle to extract the relevant information from historical data to apply Bayesian approach. The objective of this paper is to illustrate a methodology for identifying the value of information in reservoir management, in particular for deriving the conditional probabilities of success when new and imperfect data are acquired. A methodology to assess the value of reservoir surveillance is supported by two cases. In the first case, the incremental value of Real-Time Reservoir Characterization (RTRC) in underbalanced drilling (UBD) was nearly 100 times the cost of the services; in the second case, the incremental value of permananet downhole gauges (PDHG) was near 230 times the cost of installation and services. Reliability of facquired data, among other uncertainties, resulted to be a key success factor for both cases; however, in worst-case conditions, the incremental value was always positive.
The objective of this paper is to demonstrate the application of MRC drilling for an increase of production demand and enhancing reservoir management strategy. A case study is presented herein for a layered carbonate reservoir, undergoing redevelopment plan with water injection scheme, where MRC strategy was deployed to tackle challenges of pressure maintenance and water breakthrough mechanism and limited wells productivity in tight area, Average porosity 20-23% and Average Permeability 2-30 md. Drilling and evaluation of 3 MRC wells was carried out in phases. The Planning phase included the reservoir modelling, selection criteria. Simulation modelling evaluated prospective performance in terms of oil sweep and cumulative production and effective well length range. The completion design assessment called for limited entry liner (LEL) completions to assure effective acid stimulation. In the execution phase, optimized well placement via Geosteering tools and the LEL completion set up is illustrated. Post commissioning, the technical evaluation for the MRC cases included a thorough surveillance monitoring base line of PLTS and MRT analysis pre and post stimulation. The evaluation results of MRC cases with conventional wells proved the value of MRC to accelerate production reserves and pressure support with higher wells deliverability. The three MRC wells deployed showed promising performance. Oil producer (OP-X1) was able to produce at almost double rate of nearby wells with lower drawdown, no Water breakthrough detected, and PI doubled post stimulation. Water injector (WI -X2) met the injection target and was scheduled for stimulation as the PLT showed that approximately 25% of the wells length was not contributing. One additional WI-X3 proved successful without stimulation. In overall first application of MRC led to: Well count optimization during the redevelopment phase (reduction of 20% total wells).Reactivating inactive elongating well life by minimizing inverse coning.Increasing and accelerating rates, +2 times and well PI/II enhancement by more than two folds.Water injection capacity enhancement and accelerated pressure support.Uniform profile across Horiz drain with Leff more than ~75% with LEL design.Estimated Capex saving of +24 MM drilling/surface tie in cost. The analysis presented helps to propose actions to improve and define the best production/injection scenario for efficient MRC deployment. The promising results can be a guidance to extend the implementation of the MRC for field development/re-development plans tackling pressure maintenance issues and tight reservoirs WBT mechanisms. The case studies presented capitalizes on Reservoir management best practices displaying systematic approach to screen and assess MRC well candidates (pre- and post-deployment) to maximize probability of success.
Maximum Reservoir Contact (MRC) drains have been introduced and implemented as an attractive solution in reservoir developments to accelerate production/injection while optimizing the development costs. The main objective of this paper is to provide a workflow to assess the optimum well length (Lopt) and MRC wells evaluation. In addition, it aims to highlight the factors affecting actual Effective well length (Leff) based on a study performed on a giant oil field and the planned execution plans to mitigate wells with poor effective well length. A new approach is proposed to predict the optimum well length based on the proportionality of flux rates and productivity index (PI). The approach uses steady-state well modelling packages built using the static well data such as trajectories, reservoir/fluid properties, vertical and lower completion tuned with dynamic data such as surface well test data and downhole P& T measurements. Output results are oil influx rates along the trajectory, PI and production profiles. For the sensitivities, an automated well model base calculation was implemented through an Excel-Macro to facilitate performing different realizations of wellbore design, permeability ranges, and tubing sizes. Next, the evaluation of horizontal wells was assessed utilizing surveillance tools with the integration of the several factors affecting the effective well length. Prior to implementing MRC drilling, the asset team must assess the optimum well length (Lopt) for their reservoir settings where a certain limit for horizontal section indicates an increase in frictional losses and increment (Q, PI) is no longer favorable. Theoretical models indicate productivity and rates proportionality with horizontal length. While field case evidence of wells surveillance show effective length is rarely 100%. The findings proved the tool's efficiency to predict Lopt with the capability to reduce simulation runs/efforts for multiple scenarios. For the studied reservoirs, the Lopt was inferred to be in the range of 9000 up to 16,000 ft depending on the permeability, fluid properties, completion size and surface back pressure. Tubing diameter size was found to have a major influence on the flux rate, while wellbore diameter had a negligible impact. The workflow assessment on field studies with average conventional wells and MRC wells length of 1800 ft-10,000 ft inferred significant factors affecting actual well effective length to be: Well placement (Porous/dense), Heel-toe effects, Damage while drilling, production/Injection rate, Barefoot vs. completion, acid Stimulation after drilling, Well accessibility due to hole condition and production rate limits (Spinner threshold). The tool will help in the preliminary assessment to decide the optimum well length for the MRC, considering the reservoir settings and multiple completion options. In addition, the application can be extended to integrate with dynamic simulation as a robust tool to optimize completion design to be fit for future conditions. Furthermore, the field case set a generic workflow for confirming factors that may impact the Leff and evaluate MRC performance.
Proper hydrocarbon field management requires evaluating downhole production and injection efficiencies. This process can however be very challenging in many well configurations with behind pipe or formation flow, such as horizontal wells, wells with inflow control devices (ICDs), or in dual and triple string completions, especially when using standard logging techniques. This paper highlights how additional measurements, such as high-sensitivity spectral noise and fast-response temperature, can improve the quantitative analyses obtained with conventional production logs (PLT). Production log analysis typically provides very reliable flow profiles inside the wellbore, but much of what is going on behind the pipe or directly in the formation around the well is hidden from the PLT sensors. The downhole flow environment is more completely characterized, however, by complementing the PLT analysis with spectral noise and thermal modelling, and current technology makes this possible on a single run in the well. Several regional cases are presented to show the technology and the results from the individual analyses, demonstrating how they can be integrated to improve the understanding of the downhole panorama. The case studies presented in the paper were selected from some of the more complicated operating environments in UAE production wells and are used to demonstrate how spectral noise and temperature data can successfully complement the downhole analyses obtained from specialized production logging sensors in these high-angle wells. The noise tools used for these logs are highly sensitive instruments recording across a wideband frequency spectrum to acquire noise signatures from very small fluid movements in and around the wellbore. The addition of thermal modeling on the high-resolution temperature data improved the flow profiling in the surrounding formations. The presented cases include producer wells, along with different types of lateral completions. Objectives among the examples also vary, showing production profiling, investigation of formation fluid movement, evaluation of flow behind casing, and diagnosis of leaks in the completion. The acquisition of data sets with different types of sensors not only helped improve the dynamic downhole analyses but also enabled corroboration of the responses among the tools, ultimately increasing the reliability of the interpretations provided to the well operator in these complex conditions. The case studies presented will demonstrate how operators can benefit from the effective use of the latest generation of spectral noise tools to qualitatively identify production intervals, in combination with thermal modelling to quantitatively estimate fluid distribution, and with production log data for wellbore flow and fluid profiling. The improved understanding of the downhole fluid dynamics is used to program more informed interventions, optimizing production efficiency, and overall field and reservoir economics.
Water injection is by far the most popular method used in the secondary recovery phase of field development for oil displacement and pressure maintenance. Proactive reservoir management is important to validate the efficiency of the existing water injection schemes and to assess field development strategies to prolong oil production plateau and improve the recovery factor (RF). The main challenges arise in stretching the reservoir target whilst ensuring stabilized or reduced water cut (WCT), minimizing by-passed oil volumes and preventing wells from becoming inactive due to high WCT. In order to mitigate premature water flooding issues, mainly two options are available: (1) artificial lift techniques to activate producers suffering early and rapid water breakthrough; and (2) optimized completion designs via preventive or corrective controls. Preventive (i.e. proactive) approach involves segmenting the wellbore using sliding sleeves, influx control equipment, limited-perforated liners, while corrective (i.e. reactive) methods attempt to divert/remedy unwanted water influx via water-shut off (WSO) interventions. None of these alternatives can be fully pursued as full-field development strategies without realizing the technical limitations as well as their economic benefits. The objective of this paper is to determine the value of applying subsurface water control strategies in the context of enhancing reservoir management and develop a novel framework to assess potential remediation opportunities. The technical evaluation was supported by a robust Integrated Reservoir Management (IRM) process. This process identified the rig/rigless jobs opportunities to intervene inactive wells due to high WCT and rank all possible mitigation methods in an automated economic manner. The findings have also proved the value of installing autonomous inflow control devices (AICDs) to control water production along horizontal sections. In effect, it controlled water slumping without jeopardizing oil production of wells awaiting gas lifting. A case scenario of combined Gas-lift and ICD deployments suggested a net incremental value of $66 million (or 106%). Field test results of the horizontal well's production and WCT were found to be within 10% of the expected planned rates, and the oil gain is expected to further improve by 50% when gas-lift is commenced.
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