The Congo Section came back to life in September 2006 after more than 7 years of pause. Energized by Tony Ogunkoya (SPE Congo Chairman), the section had a thriving start with a joint Young Professional and Main Board event: "Developing Young E&P Professionals To Solve the Big Crew Change," held 22 September in Pointe Noire, Republic of Congo. Fifty-three people attended the meetings indicating a great interest in the subject and in SPE activities in Congo. As proof of such enthusiasm, the number of SPE members increased by a factor of 10 between September and November 2006.
Showing concern for the high emission of green house gases, the governments all over the world are coming up with more stringent rules to check the emission level. Steam Assisted Gravity Drainage is a highly energy intensive process where huge amount of steam is generated by heating natural gas or coal thereby generating a very large share of green house gases. Therefore, solar energy seems to be lucrative in the following ways: world areas with abundant solar irradiation level can be tapped to reduce the fossil fuel consumption, minimizing the cost spent on fossil fuel and the emissions level at the same time. Concentrated Solar Power (CSP) looks a very promising technique but it comes with its own limitations mainly due to the requirement for huge area for setting up the solar collectors. Water Soluble Carbon-N115 is a sub-micrometer particle that has size less than the wavelength of light. Due to this reason, instead of scattering light, it absorbs light. The nano-particle gets enveloped in a thin layer of steam when put in a water bath. The vapour is released after reaching liquid-air interface and the nano-particles revert back to the solution to repeat the vaporization process and they exchange heat with the fluid, slightly raising the fluid temperature resulting in boiling of the fluid volume as a parallel effect. The paper discusses a model incorporating this nano-particle for the reduction of solar field footprint by more than a quarter and thereby reducing the cost and operational area. The paper also suggests the places across the globe where the proposed method can be deployed for generating steam and ultimately injecting it for producing oil above the surface from a tar-sand reservoir.
Juárez-Morejón, Jose L. (University of Bordeaux) | Bertin, Henri (University of Bordeaux) | Omari, Aziz (University of Bordeaux) | Hamon, Gerald (Total) | Cottin, Christophe (Total) | Morel, Danielle (Total) | Romero, Carolina (Total) | Bourdarot, Gilles (Total)
An experimental study of polymer flooding is presented here, focusing on the influence of initial core wettability and flood maturity (volume of water injected before polymer injection) on final oil recovery. Experiments were performed using homogeneous Bentheimer Sandstone samples of similar properties. The cores were oilflooded using mineral oil for water-wet conditions and crude oil (after an aging period) for intermediate-wet conditions; the viscosity ratio between oil and polymer was kept constant in all experiments. Polymer, which is a partially hydrolyzed polyacrylamide (HPAM), was used at a concentration of 2,500 ppm in a moderate-salinity brine. The polymer solution was injected in the core at different waterflood-maturity times [breakthrough (BT) and 0, 1, 1.75, 2.5, 4, and 6.5 pore volumes (PV)].
Coreflood results show that the maturity of polymer injection plays an important role in final oil recovery, regardless of wettability. The waterflood-maturity time 0 PV (polymer injection without initial waterflooding) leads to the best sweep efficiency, whereas final oil production decreases when the polymer-flood maturity is high (late polymer injection after waterflooding). A difference of 15% in recovery is observed between early polymer flooding (0 PV) and late maturity (6.5 PV). Concerning the effect of wettability, the recovery factor obtained with water-wet cores is always lower (from 10 to 20%, depending on maturity) than the values obtained with intermediate-wet cores, raising the importance of correctly restoring core wettability to obtain representative values of polymer incremental recovery. The influence of wettability can be explained by the oil-phase distribution at the pore scale. Considering that the waterflooding period leads to different values of the oil saturation at which polymer flooding starts, we measured the core dispersivity using a tracer method at different states. The two-phase dispersivity decreases when water saturation increases, which is favorable for polymer sweep.
This study shows that in addition to wettability, the maturity of polymer flooding plays a dominant role in oil-displacement efficiency. Final recovery is correlated to the dispersion value at which polymer flooding starts. The highest oil recovery is obtained when the polymer is injected early.
Eni installed the world's first offshore Rigless Fully Retrievable Electrical Submersible Pump (RFR-ESP) system in an Eni Congo field in April 2012. The ESP failed after four years, and the system was successfully replaced rigless, by means of a slickline unit and a pumping unit.
The job included the complete path from design and operations definition to the ESP commissioning and follow-up.
Replacement operations were split in three different phases: Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s). Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole. Run In Hole (RIH): system deployment, commissioning and follow-up.
Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s).
Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole.
Run In Hole (RIH): system deployment, commissioning and follow-up.
The separation in time of the three phases was mainly due to the logistic arrangements required for the shipment of the various items to be replaced.
Major attention was given to HSEQ aspects in every phase.
The job resulted in the complete rigless replacement of the retrievable part of the ESP system, which allowed remarkable cost savings, compared to a rig intervention for the same scope of work, in terms of both direct costs and gains for avoiding well downtime and production delay.
Better results and further contractions of times and costs could have been achieved by improving the management of operations and logistics. However, being this the first job of this kind worldwide, it was challenging in that no model or benchmark was available at that time.
Some lessons learnt from the POOH phase were directly applied during the RIH phase, while others were reported in order to be implemented in future similar jobs. Since the economic impact of this type of job is remarkable, the sharing of knowledge is key to enhance performance of analogous applications, in a safe and efficient manner.
This paper describes the job performed, explaining the choices made, the criticalities encountered, as well as the lessons learnt and the benefits achieved.
Tony, Chembou Mike (Perenco Congo) | Bruno, Valeri (Perenco Congo) | Loïs, Crevoisier de (Perenco Congo) | Michel, Akue (Perenco Congo) | Vincent, Rodet (Perenco Congo) | Gabriele, Ghia (Schlumberger Congo) | Achille, Mouamba (Schlumberger Congo) | Ali, Lazzem (Schlumberger Congo)
Congo has been an oil producing country since the 70's, it is in this context of aging oilfield and low oil price environment that a redevelopment project was launched to give a second life to a shallow, depleted, mature, offshore oilfield with viscous oil (22 API) in a cost-effective manner. The solution selected was to drill "U-shape" side tracks (inclination at TD 115deg) from the original boreholes on an existing platform (60m WD). The objective was to create a second drainage area of up to 500m, 200m away from the original producing zone. Five reentries U-shape wells were delivered with measured to vertical depth ratios up to 2.5 in shallow heavily depleted reservoirs (270m TVD). The team selected innovative and low cost techniques to overcome many challenges, from high DLS in unconsolidated formations using simple mud motor BHA, to running 4-1/2" liner up to 115deg inclination and implementing a thixotropic mixed metal oxide mud system to mitigate losses. The project has been successful both from a budget and production standpoint.
A major operator manages multiple, multiwell deep water projects in West Africa. For two such projects in Congo and Nigeria, it was determined that sand control was necessary and a stand-alone screen (SAS) completion was an efficient and cost-effective means for providing sand control for the majority of wells in both projects. This paper describes a new and unique feature of the SAS completion, called the Dual-Isolation Assembly (DIA), which addresses many challenges, and its application in Nigeria on the Egina Project.
Standard SAS completions incorporate a circulation path down the workstring, through the float shoe, and back to surface through the workstring by casing annulus for circulation, pressure maintenance, and removal of the filter cake at the operation's conclusion. The capability to wash down through the toe of the system while running in the well requires washpipe seals inside the float shoe, which incorporates spring-loaded valves that open during pumping, but close when pumping stops. In addition to the wash-down capability, the washpipe incorporates a shifter for closing an uphole isolation valve with the ability to reopen the valve, if necessary.
For an injector well, the flow path into the formation is through the sand-control screens and float shoe from the inside. The path is the opposite for a producer well, which flows from the formation to inside the screen while the float shoe is closed. Because of the different natures of the flow paths, the float shoe is continuously exercised in an injector well as a result of injection fluid starts and stops. During injection, if the opening pressure of the float shoe spring is exceeded, it could stay open over time, causing loss of integrity of the float shoe. When pumping stops, the flow path into the screen through the float shoe could heave formation particles back into the wellbore, as a result of the reservoir being energized upon injection shutdown. The DIA provides secondary and permanent isolation of the float shoe, as requested by the operator, and is capable of shifting a barrier isolation valve installed in the lower completion to comply with the operator's barrier policy for deepwater wells. The DIA and lower completion design allows the operator to safely place a filter-cake breaker treatment in the open hole after setting a lower completion packer.
In addition to fulfilling the requirements of these SAS completions, the DIA design addresses other potential challenges, such as hydraulic locks and any potential swabbing while manipulating the service tools. This paper describes the evolution of the DIA design and full QA/QC and operational procedures, which led to the successful deployment and excellent functionality of the DIA in 12 completions run to date in Nigeria.
The use of conventional downhole batteries, which are intended for low voltage/current, faces hurdles when it comes to operating tools designed for surface power provided through a cable. The high power consumed by some of these tools requires careful characterization of parameters such as current, transients, and battery capacity at different loads and temperatures. The battery power tool developed for high-power tools uses three battery packs, here used in series, to boost input voltage, with a provision to use three additional packs in parallel for additional current. Battery characterization efforts at currents higher than 1 A were performed at different temperatures (75 C, 100 C, and 150 C) to explore the behavior of lithium battery chemistry, with a total of 48 battery packs tested. The electronics design to boost battery voltage up to 200 V to support a pulsed neutron tool is also presented. The result of this engineering effort is a system that can provide more than 20 Ah of power and enables more than 10 hours of continuous operation of pulsed neutron tools. It also allows more than 100 hours of operation of conventional production logging tools. A tool planner software is provided for the field users to estimate the battery operation time for a specific job. Those benefits are illustrated by the field deployment results of this solution since 2014, with examples of successful operations in the Kingdom of Saudi Arabia, the Congo, and Gabon.
Cementing the 20" surface casing in offshore Angola is associated with low fracture gradients and shallow water flows. These particular challenges require the use of lightweight slurry with both bead materials, and tight fluid loss control which was the initial approach for the section mentioned above. Due to high slurry volumes, rig site bulk logistics deployment, and budget, Foam cement was proposed. The Paper describes the design methodology and implementation of an automated foam cement system with real time monitoring. Based on the challenges presented above, Foam cement slurry has been the choice for some operators in Angola. Using a constant N2 injection rate with a foaming agent and a stabilizer that are injected into the slurry prior to it reaching the foaming "T" with variable choke bean size where N2 is injected into the slurry prior to pump downhole. Specific developed software’s, and Local training classes with in class and field training have proven to be very efficient allowing to have flawless execution pre and post job comparison and data evaluation.
The foamset cement system has shown to be very reliable and efficient on covering shallow surface areas likely to preserve fresh water aquifers. A standard slurry design was developed; thickening time adjusted depending on well conditions. The slurry was stable both at surface and downhole conditions with foam quality varying from 20% to 35%, providing required compressive strength. Since the implementation in Angola, 26 jobs have been performed successfully. This slurry can undergo a wide range of downhole pressures and temperatures variations without deforming the cement in place and or compromising well integrity.
This paper will share experience and success acquired in offshore Angola with best practices used in laboratory testing, both operations and engineering planning, execution, and post job data results.
Epryntsev, Anton (LLC NOVATEK NTC) | Minikaev, Farid (LLC NOVATEK NTC) | Sullagaev, Alexey (LLC NOVATEK NTC) | Yazkov, Alexey (LLC NOVATEK NTC) | Khachaturyan, Benik (CJSC NORTHGAS) | Vildanov, Eldar (CJSC NORTHGAS) | Fastovets, Andrey (Schlumberger) | Erdman, Andrey (Schlumberger) | Selivanov, Sergey (Schlumberger)
Frequently, production from gas and gas condensate wells is negatively impacted by the wellbore accumulation of liquid – a mixture of water and condensate. As reservoir pressure and tubing gas velocity decline and produced water cut increases, heavier liquids can no longer be effectively removed from the wellbore, resulting in the liquid column build-up at the bottomhole. This creates additional backpressure on the producing formation and leads to gradual production decline, until the well completely stops producing – the condition widely known as "liquid loading". Use of smaller size tubing (velocity string) is often the simplest and most straightforward solution, but depending on reservoir properties (water cut, productivity and pressure) and well completion (vertical, slanted or horizontal) this approach may not be efficient. This paper describes the technical approach to resume continuous production from liquid-loading gas condensate wells at North Urengoy field. It is shown that Electric Submersible Pumps (ESPs) can be successfully applied to unload horizontal wells producing large amounts of water. In this application, water and condensate is lifted by the pump through the tubing string, while gas and condensate mixture is simultaneously produced through the annular space between the tubing and the casing. Reviewed in detail are the technical challenges of modeling the well and pump performance using dynamic multiphase flow simulators, and the ESP design for the pilot application in deep, horizontal gas condensate well in Russia.