Using examples from the Permian Basin of Texas, the North Slope of Alaska, and the Bergan Field of Kuwait, this paper describes how oil geochemical fingerprinting can be applied to diagnose quickly and easily three production problems that may affect highly deviated wells. High-Resolution Gas Chromatography can be used to quantify ~1,000 different compounds in an oil, and the relative abundances of those compounds form a geochemical fingerprint. Geochemical differences between fluids in adjacent reservoirs can serve as natural tracers for fluid origin, allowing changes in production in highly deviated wells to be understood. Application 1: In wells that are fracture stimulated, oil fingerprinting can be used to assess whether induced fractures have propagated out of the target interval and into overlying or underlying formations. Oil fingerprinting can be used to quantify what percentage of the produced oil and gas is coming from each interval and how the effective stimulated rock volume changes through time. This concept is illustrated here with a Permian Basin example. Application 2: In wells with multiple laterals in the same well (such as those in certain North Slope, Alaska fields), sand can settle out of the production stream and form sand bridges that obstruct production from one or more of the laterals. In addition, sand co-produced with oil from shallower laterals can settle at the bottom of the vertical section during regular production and obstruct the entry to a deeper lateral. Geochemical fingerprinting can be used to determine quantitatively the contribution of each of several zones to a commingled oil stream. This technique allows the operator to identify sanded-out intervals for fill cleanout (FCO). Application 3: If two reservoirs are both oil bearing, but are of very different permeability, horizontal wells with an intended landing target in the tighter reservoir may be adversely affected if the well path contacts the more permeable reservoir. The Mauddud reservoir in Kuwait provides examples of this phenomenon. The Mauddud carbonate occurs between two massive clastic reservoirs, the Wara and the Burgan. Average Mauddud porosity is 18% with low permeability (1-10 mD), characteristics which make this reservoir a candidate for horizontal drilling. However, some lateral wells in this carbonate may encounter the adjacent, more permeable reservoirs over a short portion of the well path. In such cases, production from the adjacent reservoir may account for virtually all of the well's production, even though the well was intended to be completed solely in the tighter reservoir. Oil fingerprinting can be used to identify wells affected by this problem. A common theme unifies these three applications: Geochemical differences between in-situ fluids in adjacent reservoirs can serve as natural tracers for fluid movement. However, these techniques have been under-applied as tools for optimization of production from highly deviated wells. This paper illustrates the application of this technology to that well type in a variety of play types.

This paper presents a field case study of conformance engineering efforts completed in the West Sak field throughout the past eight years. The West Sak field is a shallow viscous oil reservoir with poorly consolidated sand that has been under waterflood since 1998. Because of the nature of the formation and the completion techniques used, the field has experienced some severe conformance issues. Conformance candidate identification and selection criteria are reviewed followed by an overview of additional problem characterization efforts. A variety of solution designs considered and attempted are discussed with a summary of lessons learned from both failures and successes during this effort. This review discusses treatments that range from pumping graded CaCO3, molten wax, special cement blends, and, finally, preformed particle gels (PPGs) or water swelling polymer (WSP) crystals. A majority of these treatments were executed on horizontal wells, which required adjustments for some challenging placement control dynamics. A review of the efforts to control those placement dynamics is presented, discussing some potential problems associated with that control. The principle objective of this work was the elimination of open channels connecting water injection wells with oil producers. This connection eliminated matrix flow between the wells and threatened secondary recovery potential. Ultimately, the evolution of current solution treatments is provided with a brief benefit summary of the overall performance of this effort.

In multilateral wells, several distinct processes including sand production, mechanical failure, and pattern depletion can cause a decrease in overall well performance over time. Within a lateral, sand can fall out from the production stream and form sand bridges that obstruct production from that lateral. In addition, sand co-produced with oil from shallower laterals can settle through the production stream to obstruct the entry to a deeper lateral. However, a decrease in production cannot be assumed to be due to obstructions formed by co-produced sand, since a variety of completely different processes can also reduce production. It is critical to know the cause of decreased production from a well, since which method is used to reverse the decrease in production very much depends on the cause of the decrease.Geochemical techniques can be used to quantitatively determine the contribution of each of several zones to a commingled oil (or gas) stream. This technique costs less than 1-2% of the cost of production logging. One particularly useful application of this technique is using oil fingerprinting to identify sanded-out intervals for fill cleanout (FCO) In brief, production allocation is achieved by identifying chemical differences between end-member oils (single-zone samples collected from each of the zones being commingled). Parameters reflecting those compositional differences are then measured in the commingled oil. Those data are then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end-member oils. That result is achieved using a linear algebra manipulation of the concentrations of 150-250 compounds naturally occurring in the end member oils and the commingled oils.In the current study, we show three examples where this approach was used to identify a sanded out interval in each of three wells. Once the sanded-out interval was identified, an appropriate FCO operation could be conducted. This approach resulted in increased production of 200 BOPD, 500 BOPD, and 400 BOPD in the three respective wells. For those wells, the cost of the geochemical analysis was less than the value of 1 hr of increased oil production.

This paper is not a technical paper about electric submersible pumps (ESP's), instead it traces the 20-year journey that has led to the development and successful application of multiple generations of rigless ESP conveyance systems in a commercial oilfield. The end result, after many lessons learned, is a success story in which over 300 rig interventions have been eliminated over a 20-year period, with savings of 100's of millions of dollars in intervention costs, reduced HSE exposure and many millions of barrels of additional production. Utilization of ESP technology in the West Sak viscous oil field in Alaska is challenging. The unconsolidated nature of the West Sak sands impacts the performance and reliability of conventional ESP systems due to sand production. This challenging environment causes ESP pump erosion and accumulation of sand in the tubing above the pump and in the lower completion below the ESP. The initial development of the West Sak formation was the basis for the original development of the through-tubing conveyed progressing cavity pump (TTCESPCP) in the mid 1990's. With time, the West Sak completions evolved from vertical wells to long horizontals, resulting in production capacity increasing beyond the capabilities of the 3.5 in. and 4 in. TTCESPCP systems. This led to the development of a 4.5 in. through-tubing ESP in the early 2000's. In this design, the PCP of the TTCESPCP system was replaced with a high capacity, centrifugal pump or through-tubing convenyed ESP (TTCESP). With time and successful experience utilizing the TTC systems, it became evident that although the through-tubing technology resulted in significant savings and increased production, the design was lacking in one major aspect – the ability to remove sand accumulation in the 7-5/8 in. production casing below the end of tubing. The inability to perform interventions without pulling the tubing, was leading to expensive and avoidable rig workovers not related to the ESP equipment. The resulting economics drove the development of a through-tubing, slickline (SL) deployed ESP that, when all components are removed, leaves a minimum diameter of 3.80 in. for well interventions below the end of the tubing. The wireline retrievable ESP (WRESP) system was launched in 2005 and was fully commercialized in 2014. Numerous papers have been written on this specific technology and references are provided at the end of this paper. This list does not represent a complete listing of all through-tubing technologies, as there are other systems with substantially different characteristics. This paper will focus only on the through-tubing technology development and evolution in Alaska. It will present the 20-year development history of the Alaskan through-tubing technology, how the system is deployed, answers to frequently ask questions, and as the title suggests – What went Right, What went Wrong, and What's Next? The development and successful commercial deployment of through-tubing ESP systems in Alaska has been a long journey, with many lessons learned in the evolution from conventional ESPs, to through-tubing PCP's and ESP's (TTC or Generation 1 (Gen 1)), to the wireline retrievable ESP (WRESP or Generation 2 (Gen 2)). It should be recognized that both technologies had a development phase, followed by a commercial deployment phase. There were unexpected problems and benefits that were encountered as the technology matured. The technical difficulties significantly increased while advancing from the TTC (primarily mechanical changes) to the WR technologies (which adds the electrical component of a downhole wet connect).