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Cementing is an important aspect of the good construction process, helping with wellbore integrity from the reservoir face to the surface wellhead.  Typically, it can be divided into primary and secondary cementing classifications.  Primary cementing relates to pumping cement to seal the annulus after a casing or liner has been run.  Secondary cementing includes cement plugs placed to seal lost circulation zones, provide a kick-off for directional tools or well abandonment.  It can also relate to remedial or squeeze cementing performed to repair, as an example, a faulty primary cement job.  Another use of cement plugs is for addressing the loss of circulation zones during drilling.

When successful, cementing not only supports the casings, it also helps provide zonal isolation which is critical to the long term, trouble-free life of the producing well.  When there are design, material, or execution shortfalls, costly remediations may be needed to address inter-zonal fluid communications, formation water entry, corroded casing, loss of good pressure, unpredictable good behavior, and other debilitating challenges. 

Well Driller


Drilling fluids can be water based, oil based or synthetic, the choice being dependent on the geological setting, operator experience and logistical and environmental considerations.  Along with chemicals such as stabilizing and fluid loss additives, weighting agents such as barite and hematite form a bulk part of drilling fluids.

Lost circulation while drilling can result in lost time.  Porous or vuggy formations can result in drilling fluid losses, accumulating time and material costs.  They can also contribute to non-optimized well construction. The drilling team needs to carefully anticipate such situations and have ready action and treatment plans.  Conversely, the loss may be in a naturally fractured rock which requires a different approach.  A particular situation may call for a temporary or more permanent solution.  



As the name implies, stimulation is carried out to stimulate a well to increase production either by restoring or enhancing productivity. Typically, matrix treatments carried out influence the wellbore and address drilling damage and near wellbore clogging to restore natural hydrocarbon production. Based on the nature of the formation, a suitable acid mixed with carefully selected chemicals is used to soak the matrix setting.  Fracturing is another approach that is used to enhance production from the reservoir.  This is done either through hydraulic or sand fracturing by pumping fluids at above reservoir frac pressures typically in sandstone reservoirs or by acid fracturing in carbonate formations. 

Hydraulic fracturing creates cracks or fractures deep into the reservoir and with the crack under pressure, propagates sand into the cracks so that permeability is induced when the crack closes upon relieving the pressure.  Acid frac etches or dissolves a path into the reservoir in the case of carbonates, or enlarges pores in the case of sandstones, to enhance oil production.  In unconventional or shale reservoirs, hydraulic fracturing plays an important role in creating production, and often the treatment needs repeating periodically.  Some of the chemicals that are used in a stimulation design include corrosion inhibitors, surfactants, iron control and chelating agents, foamers and defoamers, gelling agents and friction reducers, solvents, clay stabilizers and emulsion and sludge preventers.  Proppants used in fracturing can be sand grains or specially made ones like resin-coated sand or ceramic material.



Downhole tools are often used in workover and well completion operations as well as during drilling to sidetrack or isolate casing sections.  Packers can be used to isolate the annulus for squeeze cementing, stimulation or carrying out well testing.  


Compression set retrievable and permanent packers and plugs are the mainstay of downhole tools in drilling and workover operations. Multiple zone production packers or gravel pack packers as the need may be, are used in completions to provide efficient production mechanisms. Depths, pressures and temperatures dictate the specifications of the downhole tools that are used in specific settings.



Accurate and quality laboratory services go hand-in-hand with jobs executed as designed with no surprises or non-productive time. 

Cement laboratories provide the main tests that are required for any cementing operation – rheology measurement, fluid loss testing, free water tests, slurry thickening time measurements and compressive strength tests. Other tests that supplement are water quality tests, cement-mud-spacer compatibility tests and cement supply quality assurance and quality control (QA/QC).

Stimulation and production laboratories handle fluid compatibility tests, scale dissolution tests, emulsion and sludge testing, along with acid strength and solubility testing and scale and water analysis. 



When it comes to primary cementing, using drilling and well parameters, advanced computer software is used to design and optimize various cementing job parameters.  The software integrates well and drilling fluid details together with formation characteristics to propose a primary casing cementing design catering to well hydraulic security, mud removal and cement placement.


Once the job is carried out, the data from the well site such as operational record can be imported back into the software to compare design to execution and generate a predicted cement bond log. This can be compared with actual logs. A similar approach can be adopted on cement plug jobs.  On stimulation jobs production data can be used in lieu of cement logs.



Exploration and development projects in technically challenging, new and remote frontiers often present challenges in terms of time, costs and logistics.  When the operation is outside of the normal area of experience, outsourced project management or turnkey operations can bundle the broad scope of well construction under one contract, covering planning, logistics, design, engineering, drilling operations, supervision and more to achieve focused in time execution.  The scope can include management or inclusion of third-party services with defined single point of contact.  Harnessing innovative business models like risk-reward, reimbursable price list or lump sum, such an approach minimizes risks, maintains health, safety and environment performance and can keep project costs on budget.

Remote and new areas of operation present demanding logistical readiness and challenges.  When not carefully planned and supported, costs can escalate and put the project well outside of its budget.  Logistics involves close partnering and shared goals to be able to achieve a smooth operation.
An early consulting engagement while planning out project management can help with technical evaluation, advice and recommendations to quickly and confidently proceed with formalizing the call for project management services.  

Double exposure of Engineer with oil ref



Produced water injection pump unit on oi


Enhanced oil recovery, or tertiary recovery as it is sometimes referred to as, is used to increase the oil reserves recovered from a particular field. It helps recover oil that would otherwise have been left behind.  Typically EOR leads to recovering 70% or sometimes even more of the oil in place, when conventional methods would have produced only upto 35% of the reservoir oil deposits.  EOR comes at a cost, and careful planning around economics is required usually contingent on the crude oil price and long term goals.

EOR can be broken down into three types of techniques - chemical flooding, gas injection and thermal recovery.  Chemical flooding can take the form of alkaline flooding or micellar-polymer flooding while thermal recovery can help heavy oil production through operations such as steamflood.  Such EOR operations rely on continuous water supplies.  One source of such a supply can be treated produced water. Groundwater is also sometimes used.


Inevitably, oil production is accompanied by water production, typically brine with total dissolved solids too high for beneficial reuse.  This produced water increases in volume as the field ages and some instances can be several folds more than the oil produced alongside.


Produced water can differ tremendously in its composition from field to field and even over the life of a well, making its handling and management challenging.  Along with the challenge comes commercial constraints and increasing costs of treatment for disposal or sustainable re-injection for reservoir pressure maintenance.  Oil recovered from produced water can generate financial returns. 



Oil and gas facilities use seawater for a number of applications, including EOR, equipment cooling, fire suppression, potable water generation, and desalter operations. The seawater must be suitably treated for biofoulants, dissolved oxygen, and suspended or dissolved solids.

Water injection is a popular method to increase production from ageing and declining oil wells. As the injection volumes are usually large, where available (typically offshore), seawater is used as the injection fluid of choice.  Using seawater takes the pressure off other potential unsustainable sources of injection water.  However, the sulphate present in seawater can precipitate insoluble salts when ions such as barium or strontium are present in the reservoir.  When this happens, production is hampered in the reservoir and the tubulars which become constricted in diameter due to scale buildup. Reservoir permeability damage can be irreversible and wellbore scaling requires expensive workover operations to remedy. As such, sulphate needs to be removed from the seawater prior to its injection.  Removing the sulphate from seawater also prevents reservoir souring which results from the interaction with sulfate-reducing bacteria present in the formation.  If unchecked, this can generate highly corrosive hydrogen sulfide (H2S).  This is very detrimental to the operation and lifespan of equipment and can lead to downtime.  With advances in frac fluids, in areas such as unconventional operations requiring large numbers and volumes of fracs, seawater fracturing is gaining practice.  Again, the need for sulphate removal exists.

Nanofiltration (NF) membranes are gaining popularity as the small footprint, consistent and reliable technology to remove sulphates from seawater with over 99% effectiveness. Separation by NF occurs primarily due to size exclusion and electrostatic interactions.  The NF membranes remove divalent ions from the seawater to prevent barium and calcium scale formation while leaving monovalent ions like sodium and chloride to pass through.  

Sulfate removal units (SRU) require pretreatment of seawater for removal of suspended solids and contaminants prior to entering the NF membrane system. Typical pretreatment technologies have included cartridge filters, multimedia filters or a combination of both. More recently, ultrafiltration has been gaining momentum given the inherent benefits of a tighter pore structure coupled with an automated cleaning/back pulsing function.


Water is an indispensable requirement in the execution of any oil and gas operations.  From surface water to groundwater and produced water to seawater, any or a combinations of these sources may be utilized.  Emphasis is usually on curtailing unsustainable sources practicing reuse where possible.  Invariably the water requires treating before beneficial use.  


Treatment technologies such as reverse osmosis remove dissolved solids such as salts from process water.  Suspended solids can be addressed with technologies such as media filtration and ultrafiltration.  A well-designed system will provide long lasting minimum number of membranes with least fouling and downtime and often comes with system process guarantees.  An example of copious water use is in frac operations.  Providing water for such needs requires a holistic approach to oilfield water management to avoid freshwater consumption or extensive trucking.

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