Wells & HSEQ
bredford dolphin 1180
topstrip 0014 ps forside-bilde
AGR Consultancy
agr energy web and ppt copy2
816 thumb
Facilities Solutions
TRACS Training
Improving efficiencies for increased production

Improving efficiencies for increased production

Craig Webster, AGRs Principal Production Technologist, gives an overview of the role of the production technologist.
The role of the Production Technologist can mean different things to different people (and organisations). However, the discipline is extensive and considers the production of hydrocarbons from the near wellbore all the way to the wellhead, flowlines and separator.

As a result a good understanding of all the associated disciplines from petrophysics, reservoir engineering, drilling and completions to production chemistry, metallurgy and geomechanics are required in order to take a holistic approach to design and implementation strategies from greenfield through to brownfield sites.
In terms of the field life-cycle the production technologist usually becomes involved at the point where Field Development Plans (FDP) are being developed, providing input relating to sandface completion types, artificial lift requirements and production chemistry considerations.

Their involvement is continuous through the Front End Engineering Design (FEED) stage as well as detailed well design and to finally looking at production issues, brownfield optimisation and decommissioning.
Presented below are examples of three areas which have required recent Production Technologist support.
Delivering the Right Product
For the Production Technologist, properly framing a project is key to ensuring the final deliverables will meet the client’s requirements. In order to achieve this, a Production Technologist often utilises a framing process for larger projects to ensure the clients expectations are fully met.
A recent framing session that I was involved in was with a North Sea operator, revolved around the possibility of extending CoP by focusing on water injection. Due to the complexity of the problem, including ageing topsides and subsea equipment as well as limited allocation data and multiple reservoir blocks, the solution was neither trivial nor obvious. Since there are pressure and rate restrictions at various points in the system, spending cash in one area can result in moving the choke point to another area of the system.
With a direct relationship between volume injected and oil produced, the challenge was to understand where to invest capital for the best possible prize, with cognisance of the fact that high initial investments, even if they give the best rate of return, might not be in the best interests of all the stakeholders.
By developing a number of high level strategies (ranging from 'do nothing' to 'fix-all') and linking these to the key decisions for each of the technical areas (i.e. reservoir, wells, subsea and facilities) it is possible to determine the best solution based on pre-defined selection criteria (e.g. NPV, rate of return on investment) optimising the operation whilst reducing unnecessary expense.
Changing Sandface Completion Design Philosophy – Saving Rig Time and Cost
The advances in drilling and completion technology over the 50-year life span of the North Sea petroleum industry has assisted in the economic development of more and more marginal fields as well as extending the life of old mature assets. Although DECC and the OGA are preparing for a significant increase in well and facilities decommissioning there are still great opportunities for future drilling and production optimisation.
A North Sea operator working a central North Sea asset commissioned AGR to look at how to reduce costs whilst still maintaining productivity from their infill drilling campaign. Historically the infill wells had been long, horizontal, cased and perforated wells. With completed intervals in excess of 2,000 feet, perforating alone was costly, in the region of £2.5 million per well. Add to this the cost of casing and cementing materials and operations the total well cost, both in terms of materials and rig days was becoming less and less viable.
By moving from a cased and perforated completion to one incorporating a pre-drilled liner (PDL), it was clear that significant savings could be made. However, simply running in a pre-drilled liner instead of cementing, casing and perforating has the potential to create more problems than it could solve.

Key aspects that AGR considered included:
  • Formation damage and return permeability
  • Selection of a drill-in fluid to prevent significant losses and allow flow back
  • Potential for sanding (moving from a perforated completion to essentially an open hole completion)
  • Requirements and operation of a washstring and washdown shoe
  • Requirements for a formation isolation valve (FIV)
  • Additional runs to test above and below the FIV.

The greatest concern when moving from a cased and perforated completion to a PDL is that the drilling mud causes excessive damage to the formation. While this is still a concern for a cased and perforated well, generally the perforations will by-pass any damage. For a PDL completion, the mud should be selected to minimise formation damage and maximise return permeability. The correct selection of drill-in mud and associated breakers help to ensure that formation damage would be kept to a minimum.
Although the operator stressed the fact that there had been little if any sanding, the change in the wellbore geometry (small perforation diameter to large openhole diameter) will result in a change in the stress distribution around the wellbore. While the hoop stress will decrease for increasing diameter, there is an associated increase in the radial stress that could lead subsequently to shear failure of the sandface under production conditions resulting in solids being produced into the wellbore.
Having established that the well can be drilled (without excessive damage to the formation) and produced (without failure of the sandface) the ability to run the PDL along a 2,000 foot horizontal section needs to be considered. In order to minimise risk of sticking while running in hole it was recommended that a concentric wash pipe with a flow crossover should be used, such as the Baker SLZXP liner hanger and running tool. This allows circulation down the inside of the PDL and flow through the PDL / openhole annulus if required. Given the extra weight of the washpipe a review of the torque and drag is essential to ensure that the completion can be run to depth taking into account the increased friction factors associated with sliding horizontal pipe in open hole and the slightly reduced strength of the pre-drilled liner due to the holes.
Finally, in order to protect the formation while the upper section of the well is cleaned out and the upper completion run, an FIV should also be considered. A ball-type capable of providing bi-directional pressure sealing with mechanical closing and pressurising the tubing to open is recommended. The option to mechanically open should also be considered as a contingency. While testing the FIV from above is straightforward, an additional run maybe required to perform an inflow test in order to ensure that the FIV is providing a suitable barrier from below.
Whilst there are significant savings to be made from avoiding cementing and perforating operations through the utilisation of a PDL, there are additional costs associated with the PDL such as return permeability testing, to ensure that the formation will remain competent during production as well as the additional runs with washpipe and infllow testing. However, even taking these into account there is potential to save in the region of 5-7 days of rig time (equating to £450,000 - £630,000) by moving to this type of completion. Incorporating the savings on perforation, and depending on rig rate, it was established that savings in the region of 40% for the lower well could be made by moving to a different completion philosophy.
Basis of Design for CO2 Injection Wells
With over £2.5 billion being invested by the UK and European governments in Carbon Capture and Storage (CCS) there is a lot of scope for developing an understanding of how gas, liquid or supercritical CO2 flows from the wellhead to the formation and through the reservoir. As part of National Grid's submission to the European Energy Programme for Recovery (EEPR) AGR provided integrated services to look at the geological structure of the storage site (known as 5/42) and the requirement for the wells to allow successful continuous injection of CO2. The scope of the production technologist was two-fold. Firstly to consider the basis of design for the CO2 injection wells and secondly to assess the life of field in-well monitoring requirements.
The design of a well for injecting CO2 into either a saline aquifer or a depleted hydrocarbon reservoir needs to consider a number of key factors:
  • The rate, pressure and temperature of the CO2 arriving at the installation
  • The initial and final reservoir pressures of the proposed storage site
  • The composition of the CO2 stream (i.e. quantity and type of impurities)
  • The reservoir fluid properties.

For injection into depleted hydrocarbon zones, arrival pressure and temperature are critical. Choking back the CO2 at surface can lead to significant temperature drops due to the Joule-Thomson cooling effect (it is possible for temperatures to drop from approximately 10 degC (typical subsea temperature) to -60 deg C. Further adiabatic cooling in the wellbore and near wellbore area has the potential to result in the formation of ice or even CO2 hydrates in the formation, depending on the reservoir pressure and residual water saturation.
The final reservoir pressure for which integrity of the storage site can be maintained primarily has an impact on capacity - but it can also impact on the number of wells required to provide injection at a continuous rate. As the reservoir pressure increases, more and more wells are required to maintain the constant injection rate. However, in the case of highly depleted hydrocarbon storage sites, where initial injection is in gas phase, there may actually be a reduction in the number of wells required for continuous injection. This is due to the increased density of the CO2 as it moves from gaseous to super critical 'dense' phase. As a result the design of a single type well is challenging for CO2 injection due to the changing nature of the injected fluid and the reservoir response
Metallurgy of the well is greatly impacted by impurities in the CO2 stream. High levels of dehydration, typically less than <100 - 200 ppm H2O can allow standard carbon steel tubulars to be used, depending on the operating conditions except perhaps for those exposed to the reservoir.
As illustrated by assignment examples above, the scope of the Production Technologist is broad. While they may specialise in one or two areas, they will have a wide understanding of the issues surrounding reservoir engineering, drilling, completion and production. This knowledge, when applied holistically, can aid in operational excellence, providing cost effective solutions to improving production efficiencies across the life of the field.

The article was published in the November issue of Oilfield Technology magazine.

More information on our Production Technology support can be found on our website.

Latest news

2017-05-16 — AGR provides EOR evaluation for development of several heavy oil fields in South America
Read More
2017-05-11 — AGR Software in strategic partnership with Salcon Petroleum Services
Read More
AGR. Pioneering Achievments™
© AGR. All rights reserved 2017. Norway l UK l Americas l Asia Pacific l Middle East l Africa