Kollamgunta, Saikiran (National Petroleum Construction Company) | G. V. R. A., Srinivasa Rao (National Petroleum Construction Company) | Singh, Harendra (National Petroleum Construction Company) | Kamal, Faris Ragheb (National Petroleum Construction Company) | Takieddine, Oussama (National Petroleum Construction Company)
One of the major challenges in the upstream oil and gas industry is de-bottlenecking of existing slug catcher/ inlet separator system during facilities up-gradation or due to changes in production rates for any other reasons. It is often found that upgrades or changes result in increased slug volume from the upstream pipelines thus making existing slug catcher or separators inadequate to handle the increased load. Even in cases of normal pigging not involving debottlenecking of existing facilities, production rates are required to be lowered. This is done as excess liquid slugs generated due to pigging may show severe operational problems in terms of level and pressure fluctuations in a separator leading to poor separation, potential liquid flooding, increased flaring, emergency shutdown and production loss. The use of by-pass pigs can effectively reduce the liquid arrival rate at the slug catcher over conventional approach by delivering a more uniformly mixed fluid even at relatively higher production rates. It thereby reduces the slug volume and hence, the requirement of increased surge capacity. Further, in brownfield applications, it enables optimal use of existing assets or avoiding new slug catcher.
Operators are reluctant to reduce the production flow rate to very low value for pigging, as this normally results in reduction in revenue. Bypass pigging, as compared with conventional pigging, is able to reduce the pig velocity even at relatively higher production rates. It, however, requires careful evaluation and design as in many cases, such as well fluid having wax, solids or high asphaltenes may result in blockage of the bypass holes thus impacting the effectiveness of the operation. Transient modeling and simulation of bypass pigging using OLGA Dynamic Multiphase Flow Simulator has been performed to address such issues.
This paper describes the strategies to address de-bottlenecking challenges due to increased surge volumes to be accommodated in the existing slug catcher/ separator system and use of by-pass pigging to overcome these. The application of the technique used i.e. bypass pigging is demonstrated by transient multiphase simulation using OLGA dynamic simulator. Proposed design solutions are based on NPCC's extensive and successful experience in tackling challenging Brownfield projects.
Traditional well plugging and abandonment (P&A) methods are not efficient. For example, section milling is time-consuming and expensive because of the number of rig days required. The milling produces cuttings, which have to be handled. Contamination of the milling fluid with oil-based mud (OBM) requires separation before disposal. Cutting casing requires pulling it from the hole.
Artificial lift utilizing Electrical Submersible Pump (ESP) supporting operations have evolved from pump installations with no access to the completion zone to the point where rigless logging intervention operations can access the lower wellbore using either coiled tubing or wireline. Access to the completion zone has been accomplished through the installation of Y-Tool and a by-pass leg in conjunction with the ESP.
The major challenge is to have the Coil Tubing (CT) plug seal assembly located on the coil otherwise a damage to the seal assembly is expected and consequently a fluid circulation might take place. CT conveyed production logging requires a CT plug to prevent production circulation across by-pass section while operating the ESP. The circulation is prevented by the seal assembly which exists in the CT plug and located on the coil tube. The Bottom Hole Assembly (BHA) consist of CT plug which included connector, sleeve and bottom crossover, all covered by the CT plug external body which has the seal assembly in addition to the Production Logging Tool (PLT). Changes in tools design and profiles allowed for a successful logging intervention into these Y-tool equipped wells while gathering required well logging data.
The paper presents technical and logistic challenges during rig-less logging operations on wells with a Y-tool and a by-pass leg with complicated downhole configuration including small restriction and dual pump layouts. Examples of both impaired and successful operations will be reviewed with challenges and lessons learned, including the changes made to allow the tools for logging activities. This paper will provide a path forward to well access and surveillance while ensuring adequate isolation during logging operation.
The reliance on Electrical Submersible Pumps (ESPs) in oil fields operations is increasing and will continue to grow in the coming years due to the eminent decline of reservoir pressure and early water breakthrough associated with high production demand overtime. More ESPs will be required to sustain production for a period of time. In addition, more wells’ data acquisition and interventions will be frequently required to monitor wells integrity and performance. Therefore, an ESP system with Y-tool bypass section is utilized to enable data gathering and access to the wellbore below the ESP assembly using coil tubing (CT) or wireline (WL) deployed interventions. Production logging operations are required to monitor well performance, water production intervals, and other well parameters via the Y-Tool-ESP completion.
The Field M phase 1 development consists of 9 production wells and 2 water injectors in offshore Sabah. Field M is the first Tension Leg Platform (TLP) in Malaysia with several unique flow assurance features that were challenging for the project, namely hydrates, waxy crude with high pour point and cloud point temperatures, bypass pigging for wax as base-case strategy as well as an industry first Single Combo Top Tension Riser (SCTTR) with both gas lift and production strings in a nitrogen filled riser annulus. This paper describes the experience of bringing the Field M field into operation including hydrate inhibition, well unloading, dewatering, well ramp-up and ongoing steady state operation from a flow assurance perspective. The initial well unloading process and ongoing steady state operation of the wells and flowlines are described, and comparisons are made between expected responses based on steady state and transient simulations during the design phase, and actual field data. The key challenges faced and technical findings are also documented. Lessons learned during the first year of operation are a combination of work-arounds, differences in fluid properties from those initially assumed, benchmarking of field data with predicted simulation results, and general operational experiences related to flow assurance.
The objective of this paper is to share lessons on stabilizer selection with the industry that minimize drilling and tripping problems. Ideally the stabilizers and BHA will drill a round, ledge free hole, without patterns, with minimum vibration, minimum unplanned dog legs, that reach all directional targets in one run per section. They should not constrain ROP, be able to trip in and out on elevators past ledges and hole irregularities without the need for rotation.
These lessons were based on a number of forensics observations while drilling and tripping and a physical understanding of the BHA and its effects on vibrations, trajectory, and tripping in high angle holes.
A draft of these lessons were presented at a SPE Gulf Coast section meeting in 2015 and were sent to all that requested them as well as suppliers used by this operator for comments and suggestions. It is hoped that this publication and the reasoning behind the lessons will help improve this often neglected tool.
A few significant events initiated this work. The first was a mechanical sticking event in 17 ½ inch hole where the BHA could be rotated and moved downward, but hung up trying to trip out. The formation being drilled at high angle was a vuggy limestone. Inspection of the BHA and stabilizer design found that there was a sharp, 75 degree, transition taper on one of the rotary steerable system stabilizers. This coupled with a formation ledge made it impossible to ream or trip, resulting in a lost BHA and sidetrack.
The second key event was a 6 ¾ BHA that required control drilling to avoid plugging the near bit stabilizer. This showed up as an increase in standpipe pressure and a decrease in an annular pressure gauge located above this stabilizer. The root cause was low bypass area on the near bit stabilizer.
The third event was in 12 ¼ inch high angle hole in soft rock. This required circulation on the trip out of the hole on some wells and not others. The wells requiring circulation on the trip out had high spiral stabilizers that packed off rather than passing the cuttings bed.
A practical set of lessons have been developed that may be used as a starting point for developing industry best practices. The physics behind these lessons are given so that they can be improved over time. One improvement expected is the requirement for low coefficient of friction on the stabilizer OD to minimize whirl and on the end tapers to reduce tripping hang up.
Traditional sand-management programs usually consist of several measures employed to mitigate the production of sand from wells, a process commonly referred to as sanding. Such systems include production prediction and monitoring, topside management, sand control, and "intelligent" systems (Gherryo et al. 2009). Sand control can be considered in terms of short-and long-term solutions; examples of long-term solutions (preventative measures) would be the application of gravel packs, screens, inflow control devices, and chemical stabilization methods (Abney et al. 2007). In instances where a sand-management program has not been employed or has been ineffectively delivered, sand can and is deposited in pipelines/riser systems. This can be a gradual process of continual minor deposition over time, or systems can be overwhelmed with a sudden influx of sand as a consequence of formation or completion failure. The result leads to increasing pipeline resistance, reduced flow rates, rising pressure drop in the pipeline system, and erosion, which, in turn, can lead to degradation of the pipeline/riser and topside systems (Abney et al. 2007).
Bypass pigging, compared with conventional pigging, reduces the damaging effects of the pig-generated liquid slug by redistributing gas and liquid in the pipeline. Oil-and gas-production rate, high liquid-slug flow to the slug catcher, high pipeline backpressure, and the capacity of the slug-handling facility at the receiving end are major considerations when designing a bypass-pigging solution. Various operational and engineering challenges are encountered while implementing the commonly known bypass-pigging solutions, and empirical correlations are developed on the basis of experimental results and compared with simulation results. This paper suggests an innovative bypass-pig geometry as a solution. The Thornhill-Craver equation is introduced to calculate the bypass-flow quantity and the pig velocity.
Traditional well plugging and abandonment (P&A) methods are not efficient. For example, section milling is time-consuming and expensive because of the number of rig days required. The milling produces cuttings, which have to be handled. Contamination of the milling fluid with oil-based mud (OBM) requires separation before disposal. Cutting casing requires pulling it from the hole. Handling tubulars has numerous inherent risks, and removing old tubulars, especially, could bring up naturally occurring radioactive material from the subsurface.
Decommissioning a well must always achieve permanent integrity, and central to this is the successful placement of a rock-to-rock cement barrier. Creating such a barrier, without section-milling or retrieving and pulling the casing, offers a major cost advantage over traditional methods.
Developed by Archer, the Strong-hold Barricade system (Fig. 1) leaves the casing in situ. The system perforates, washes, and cements the annulus, creating a rock-to-rock barrier in one trip (Fig. 2).
In addition, the system reduces personnel risk, in part by reducing the number of individuals required. For example, not having to pull casing eliminates the casing crew and tong operations. The system only requires a single tool operator and the cementer, who would normally be present on the rig to pump the cement.
Two features are central to this system. First are the firing heads. Most conventional firing heads are operated by annular pressure. For this system, the company developed a firing head that is operated by tubing pressure.
A contingency system with multiple sets of guns can also be used. If the first set of guns fails to create the required injection ports, the second set can be fired by annular pressure without pulling out of the hole.
The second feature is the creation of a cement base to contain the cement plug above. The cement base is effectively an integrated bridge plug. Situated immediately above an auto-gun release, the cement base is activated after the guns are released and the tool is run to below the perforated interval to provide a secure base for the cementing operation.
The cement base is set by pressuring up on a dropped ball. A pull test and further pressure then releases the base from the string. The dropped ball is retained in the base, leaving the pipe with no restriction.
Figure 1—The one-trip barrier system is shown with its components indicated. Traditional well plugging and abandonment (P&A) methods are not efficient. For example, section milling is time-consuming and expensive because of the number of rig days required. The milling produces cuttings, which have to be handled. Cutting casing requires pulling it from the hole.
Operational pigging in a 36", 120 km subsea export trunkline has been extremely challenging for a client due to large liquid hold-up and the limited onshore liquid handling capacity. Production turndown along with bypass pigging is part of the standard operating procedure in order to slow down the pig and minimize excess liquid surges. In spite of these measures, the pigging operation has resulted in slugcatcher flooding and production deferment which initiated a detailed investigation using the OLGA multiphase simulator. The hydraulic model and the pig bypass model in OLGA will be calibrated using historic field data, and pig tool operational experience to mimic the process parameters and pig tool behavior in the field. Flow assurance analysis will be undertaken primarily to understand the impact of liquid hold-up in the pipeline, estimate the ideal bypass opening and operating limits. OLGA modelling predictions will be compared against historic field pigging runs for model validation. For this purpose, the basic pipeline model was extended to include a detailed onshore slug catcher with slug suppression control system to closely mimic the actual system in the field.
One of the main challenge is this analysis is the estimation of the wall frictional parameters considered in the flow models which affect the pig motion behavior. Hence, special considerations were given to the parameters affecting the bypass pig velocity, such as bypass pig-wall frictional forces and pressure loss coefficients. These parameters were modified based on detailed 3D CFD modelling of the pig tool, desktop calculations and tool operational experience. The bypass pig model and the overall hydraulic properties in the OLGA model were consequently tuned, showing a good match against the real field data. Finally, with the tuned OLGA model, selected sensitivity studies were carried out considering the current production flowrates, receiver pressures, bypass opening etc. to recommend a desired procedure for a successful pigging campaign. Ideal pig bypass opening was suggested for the trunkline where the client could maintain normal production flowrates, whilst slowing down the pig and resulting in manageable liquid slugs. This paper discusses the challenges and the process of determining the right bypass opening for a pigging operation, along with flow assurance analysis in order to develop an effective and a safe pigging solution.