fax 01-972-952-9435. AbstractThe Jean Marie reservoir in the northeastern part of British Columbia, Canada, is one of the most active horizontally underbalanced drilled reservoirs in the world. The Jean Marie is a depleted, low permeability, fractured carbonate with low initial water saturation making it susceptible to formation damage using conventional drilling fluids. 1 Given these reservoir characteristics, horizontal underbalanced drilling is the current method of choice for operators active in the area.Although underbalanced technology has made tremendous improvements in maintaining and ensuring underbalanced conditions at all times during operations, overbalanced incidents do occur while drilling the horizontal section. These incidents can be much more damaging than drilling with a well designed overbalanced fluid.In some cases, an overbalanced event could permanently impair production from a well by as much as 75%.With the aid of real time downhole pressure gauges, these overbalanced incidents can be identified but very often go undetected, leading to a false sense of achieving the goal of minimal damage. The unidentified damage can lead to misinterpretation of production results and disappointment with underbalanced drilling.To exacerbate the problem of identifying damage, traditional pressure transient analysis of wells in the Jean Marie may yield incorrect valuation of the overbalanced incidents by underestimating the skin on the face of the horizontal well. This could be due to the difficulty of performing meaningful transient analysis on a horizontal well in a dual porosity reservoir and a general lack of knowledge of the impact of drilling related damage on fractured or highly heterogeneous reservoirs. This paper will show how, by combining transient productivity index data collected while drilling with the use of history matching techniques, overbalanced incidents can be easily identified and the impact on well productivity can be quantified.

The development of underbalanced drilling (UBD) for production enhancement has advanced significantly since the advent of this technology in the early 1990s. The basis for the initial judgment as to the success of a UBD campaign was usually limited by the information that was available at the time of project completion: project execution success and initial production rates. However, the full scope of the effect of UBD on the overall economic success of a project remains unknown for many cases. While several underbalanced field developments have sufficient production history, drilling records, and cost data available for analysis, to date the body of published literature lacks thorough, long-term case histories. This paper addresses this scarcity by analyzing several UBD projects in the Western Canadian Sedimentary Basin. The discussion includes a comparison of UBD and completed wells with the offsetting conventional producers in the same reservoir. Comparative analysis using industry-standard decline analysis and economic techniques yield technical and economic insight. To provide a balanced picture of the economic benefits that UBD can bring, both successful and unsuccessful projects are examined. The unsuccessful cases are analyzed to determine the reasons for underperformance, whether they fall into the categories of poor candidate selection or sub-optimal execution. Understanding the magnitude and the driving factors behind the success and failure of UBD projects is critical to the growth and acceptance of the technology. This paper attempts to assist in that understanding and provide a benchmark for thorough comparisons of UBD case histories for the future. Introduction Horizontal wells can be a very effective field development technique for several reasons. Horizontal techniques excel in reservoirs that are naturally fractured or highly heterogeneous or that exhibit gas or water coning problems. Horizontal wells can also benefit low-permeability reservoirs by draining a larger area per well and thus reducing the number of wells needed to drain the reservoir.1 Formation damage in highly damageable reservoirs presents the main obstacles to achieving the benefits of horizontal wells. Delivering effective stimulation treatments in horizontal wells can be expensive and difficult, so formation damage can seriously limit the effectiveness of these treatments. UBD developed as a technique for minimizing invasive, drilling-induced formation damage to allow the drilling of effective horizontal wells in damageable reservoirs. The development of horizontal UBD, in its current form, began in the early 1990s. Significant development has taken place in the areas of equipment design, operational techniques, and the understanding of what occurs in the reservoir during underbalanced operations. One considerable shortcoming, however, is the distinct lack of published literature that clearly demonstrates that horizontal UBD is an economically effective field development method compared to conventional drilling, completion, and stimulation techniques. The majority of industry knowledge on horizontal UBD is based on anecdotal evidence, in-house analyses not available to the public, and case histories focused on operational aspects or very early time production results.2–8 Published literature that examines the long-term performance of previous UBD programs is virtually non-existent. This paper represents a first attempt at addressing this issue. A number of underbalanced campaigns in the Western Canadian Sedimentary Basin have several years of production data. The following analysis of these case studies demonstrates that horizontal UBD is a viable field development technique and quantifies the significant economic benefit that can be achieved. The analysis also includes programs in which UBD was not successful and investigates the reasons for failure.

This paper describes the steps taken in the planning, design, and field implementation of an enhanced artificial lift system to address the common challenges of conventional ESP installations. A set of case studies, in two basins, reviews the field installations and sequential optimization to achieve an improvement in ESP performance. Unconventional horizontal wells have the complexity of depth, temperature, fluid composition, and rapidly declining production rates. Most artificial lift systems struggle and inadequately cope with inconsistent slug flows from a horizontal wellbore, foamy fluids, damaging solids and gas interference. In ESPs, gas interference frequently overheats the motor resulting in excessive shut downs and/or premature failures. The root cause of gas interference is flow from the horizontal wellbore that tends to be sluggy with inconsistent mixtures of gas and liquid. A downhole flow conditioning artificial lift technology designed to smoothen and suppress slug flows prior to the ESP dramatically improved ESP performance. Field implementation revealed that the technology conditioned the flow and successfully reduced slug flow behaviour showing consistent rates and pump intake pressures. With the slug flow issue resolved, this revealed an unaddressed problem not previously noted with conventional ESP installations caused by liquid lifting in the small annular space adjacent the pump. With high enough gas rates, liquid lifting past the ESP can occur, starving the pump of liquid, overheating the motor, resulting in shutdowns. In initial field trials, this problem limited the ability to drawdown past 800 psi intake pressure. Subsequent field trials solved the problem by manipulating pump intake pressure or reducing equipment size for higher gas rate wells resulting in significantly lower pump intake pressures and improved ESP reliability. The paper describes consecutive cases that implement stepchange modifications to resolve both slug flows to the ESP and annular liquid lifting past ESPs. The optimized design resulted in an extended range of pump operability, improved reliability and enhanced control and reservoir management.

The artificial lift strategy of an asset is driven by technical and economic factors. Production challenges associated with the exploitation of unconventional plays have become a key factor when planning for a life time solution. Inherent flow instabilities associated with the production of unconventional shale wells should be taken into consideration during the production and optimization of the well. Transient simulation is adopted to gain insights into dynamic flow mechanisms and consequently design for a customized tail pipe system for the life of the well. This paper describes a case study where a Horizontal Enhanced Artificial Lift (HEAL) System is implemented together with a rod pump as the artificial lift strategy for an unconventional shale asset in the US. Dynamic transient simulation was conducted to demonstrate the efficiency of the system in significantly suppressing slug flow by conditioning flow through a regulating string and separating gas from the well stream before it reaches the installed artificial lift system. Comprehensive engineering scenarios are set up to analyze the effect of production parameters on the HEAL System design against conventional production approaches, where equipment run life is compromised due to unstable flow conditions and consequently the amount of gas and/or solids that are produced through the pump. The combination of transient simulation with artificial lift demonstrates that the HEAL System is a suitable solution for the production challenges associated with unconventional reservoirs. Extending the life of the equipment allows the well to produce at a lower bottomhole pressure and manage slug flow. The solution can be extended to unconventional places where unstable production due to reservoir pressure depletion is a dominant factor.

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