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Chemical injections to assure and condition flow by preventing build-ups

In order to prevent deposition typically inhibitors are injected. Depositions or build-ups in the oil and gas processes usually are asphaltenes, paraffins, scaling and hydrates. Of those asphaltenes are the heaviest molecules in crude oil. When they adhere, a pipeline can quickly plug. Paraffins precipitate out of a waxy crude oil. Scaling may be caused by the mixing of incompatible waters or by changes in flow like temperature, pressure or shear. Common oilfield scales are strontium sulfate, barium sulfate, calcium sulfate and calcium carbonate. To avoid those build-up inhibitors are injected. For preventing freezing glycol is added.

If we want to condition the flow we have to

• prevent emulsions: they cause enormous production delays in separators

• avoid frictions like with asphaltenes

• reduce viscosity as oil is typically a Newtonian fluid

How to deal with risks associated with chemical injections

There are various risks associated with chemical injections. Sometimes the injected chemicals do not have the desired effect, sometimes the process of deposition or corrosion just continues under injection. In case too much pressure is used for the injection, the production may be damaged. Or when the tank level is not measured correctly and a platform runs short of media, production may need to stop. Those scenarios cost the operator, the service company, the oil company and everyone else in the downstream a lot of money. Refineries may charge penalties when supplies decrease or stop.

Imagine an operator being very busy running operations, while several colleagues push him to change his activities: The maintenance manager wants to take one system out of line for a periodic maintenance check. The quality manager is knocking on the door demanding the implementation of new safety-rules. The well manager is pushing him to use less dense chemicals to prevent damage to the well. The operations manager wants dense or more viscous materials to minimize the risk of buildup. The HSE forces him to mix enough bio-degradable chemicals in the fluid.

All colleagues with different demands, all pushing for ultimately the same thing: to improve operations, make them safer and keep the infrastructure fit. Nevertheless, running six chemical injection systems for eight production wells and two EOR wells is quite a challenging organization – especially when the inventory needs to be monitored, the fluid quality has to be checked, the system performance must match the well properties and so on and on. In this case it is good to automate the process and with a future perspective allow to run operations remote.

Chemical injections are daily business in oilfield services and in the production of oil and gas. They protect the infrastructure, optimize processes, assure flow and improve productivity. Besides the challenges over and under injection rates like pressure and flow, small scale inventory management increases the profitability of a single system up to a platform and for the complete organization. Inventory Management Systems only make sense when all relevant parties of the organization have easy and fast access to the data. Open networks and the compatibility of a single tank level measurement with the complete chain up to supply vessels or trucks allow control on all levels: from the platform to the headquarter. Exact performance rates of flow and level also help to avoid any risks of HSE disasters. Before the Inventory Management Solution is set up, the right field instrumentation needs to be selected. Selection criteria here are the quality of the devices concerning availability and reliability, to get them in short delivery times, to use open systems for inter-connectivity and to receive local service on a global scale. It is about to make your system

Glossary

control line

A small-diameter hydraulic line used to operate downhole completion equipment such as the surface controlled subsurface safety valve (SCSSV). Most systems operated by control line operate on a fail-safe basis. In this mode, the control line remains pressurized at all times. Any leak or failure results in loss of control line pressure, acting to close the safety valve and render the well safe.

surface-controlled subsurface safety valve (SCSSV)

A downhole safety valve that is operated from surface facilities through a control line strapped to the external surface of the production tubing. Two basic types of SCSSV are common: wireline retrievable, whereby the principal safety-valve components can be run and retrieved on slickline, and tubing retrievable, in which the entire safety-valve assembly is installed with the tubing string. The control system operates in a fail-safe mode, with hydraulic control pressure used to hold open a ball or flapper assembly that will close if the control pressure is lost.

downhole safety valve (DSV)

A downhole device that isolates wellbore pressure and fluids in the event of an emergency or catastrophic failure of surface equipment. The control systems associated with safety valves are generally set in a fail-safe mode, such that any interruption or malfunction of the system will result in the safety valve closing to render the well safe. Downhole safety valves are fitted in almost all wells and are typically subject to rigorous local or regional legislative requirements.

production string

The primary conduit through which reservoir fluids are produced to surface. The production string is typically assembled with tubing and completion components in a configuration that suits the wellbore conditions and the production method. An important function of the production string is to protect the primary wellbore tubulars, including the casing and liner, from corrosion or erosion by the reservoir fluid.

subsurface safety valve (SSSV)

A safety device installed in the upper wellbore to provide emergency closure of the producing conduits in the event of an emergency. Two types of subsurface safety valve are available: surface-controlled and subsurface controlled. In each case, the safety-valve system is designed to be fail-safe, so that the wellbore is isolated in the event of any system failure or damage to the surface production-control facilities.

pressure

The force distributed over a surface, usually measured in pounds force per square inch, or lbf/in2, or psi, in US oilfield units. The metric unit for force is the pascal (Pa), and its variations: megapascal (MPa) and kilopascal (kPa).

production tubing

A wellbore tubular used to produce reservoir fluids. Production tubing is assembled with other completion components to make up the production string. The production tubing selected for any completion should be compatible with the wellbore geometry, reservoir production characteristics and the reservoir fluids.

casing

Large-diameter pipe lowered into an openhole and cemented in place. The well designer must design casing to withstand a variety of forces, such as collapse, burst, and tensile failure, as well as chemically aggressive brines. Most casing joints are fabricated with male threads on each end, and short-length casing couplings with female threads are used to join the individual joints of casing together, or joints of casing may be fabricated with male threads on one end and female threads on the other. Casing is run to protect freshwater formations, isolate a zone of lost returns, or isolate formations with significantly different pressure gradients. The operation during which the casing is put into the wellbore is commonly called "running pipe." Casing is usually manufactured from plain carbon steel that is heat-treated to varying strengths but may be specially fabricated of stainless steel, aluminum, titanium, fiberglass, and other materials.

production packer

A device used to isolate the annulus and anchor or secure the bottom of the production tubing string. A range of production packer designs is available to suit the wellbore geometry and production characteristics of the reservoir fluids.

hydraulic packer

A type of packer used predominantly in production applications. A hydraulic packer typically is set using hydraulic pressure applied through the tubing string rather than mechanical force applied by manipulating the tubing string.

sealbore packer

A type of production packer that incorporates a sealbore that accepts a seal assembly fitted to the bottom of the production tubing. The sealbore packer is often set on wireline to enable accurate depth correlation. For applications in which a large tubing movement is anticipated, as may be due to thermal expansion, the sealbore packer and seal assembly function as a slip joint.

casing joint

A length of steel pipe, generally around 40-ft [13-m] long with a threaded connection at each end. Casing joints are assembled to form a casing string of the correct length and specification for the wellbore in which it is installed.

casing grade

A system of identifying and categorizing the strength of casing materials. Since most oilfield casing is of approximately the same chemistry (typically steel) and differs only in the heat treatment applied, the grading system provides for standardized strengths of casing to be manufactured and used in wellbores. The first part of the nomenclature, a letter, refers to the tensile strength. The second part of the designation, a number, refers to the minimum yield strength of the metal (after heat treatment) at 1,000 psi [6895 KPa]. For example, the casing grade J-55 has minimum yield strength of 55,000 psi [379,211 KPa]. The casing grade P-110 designates a higher strength pipe with minimum yield strength of 110,000 psi [758,422 KPa]. The appropriate casing grade for any application typically is based on pressure and corrosion requirements. Since the well designer is concerned about the pipe yielding under various loading conditions, the casing grade is the number that is used in most calculations. High-strength casing materials are more expensive, so a casing string may incorporate two or more casing grades to optimize costs while maintaining adequate mechanical performance over the length of the string. It is also important to note that, in general, the higher the yield strength, the more susceptible the casing is to sulfide stress cracking (H2S-induced cracking). Therefore, if H2S is anticipated, the well designer may not be able to use tubulars with strength as high as he or she would like.

joint

A surface of breakage, cracking or separation within a rock along which there has been no movement parallel to the defining plane. The usage by some authors can be more specific: When walls of a fracture have moved only normal to each other, the fracture is called a joint.

slip joint

A telescoping joint at the surface in floating offshore operations that permits vessel heave (vertical motion) while maintaining a riser pipe to the seafloor. As the vessel heaves, the slip joint telescopes in or out by the same amount so that the riser below the slip joint is relatively unaffected by vessel motion.

wireline

Related to any aspect of logging that employs an electrical cable to lower tools into the borehole and to transmit data. Wireline logging is distinct from measurements-while-drilling (MWD) and mud logging.

drilling riser

A large-diameter pipe that connects the subsea BOP stack to a floating surface rig to take mud returns to the surface. Without the riser, the mud would simply spill out of the top of the stack onto the seafloor. The riser might be loosely considered a temporary extension of the wellbore to the surface.

BOP

A large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation.

BOPs come in a variety of styles, sizes, and pressure ratings.

Some can effectively close over an open wellbore.

Some are designed to seal around tubular components in the well (drillpipe, casing, or tubing).

Others are fitted with hardened steel shearing surfaces that can actually cut through drillpipe.

Because BOPs are critically important to the safety of the crew, the rig, and the wellbore itself, BOPs are inspected, tested, and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type, and legal requirements. BOP tests vary from daily function testing on critical wells to monthly or less frequent testing on wells thought to have low probability of well control problems.

tensile strength

The force per unit cross-sectional area required to pull a substance apart.

yield

The volume occupied by one sack of dry cement after mixing with water and additives to form a slurry of a desired density. Yield is commonly expressed in US units as cubic feet per sack (ft3/sk).

sulfide stress cracking

A type of spontaneous brittle failure in steels and other high-strength alloys when they are in contact with moist hydrogen sulfide and other sulfidic environments. Tool joints, hardened parts of blowout preventers and valve trim are particularly susceptible. For this reason, along with toxicity risks of hydrogen sulfide gas, it is essential that water muds be kept entirely free of soluble sulfides and especially hydrogen sulfide at low pH. Sulfide stress cracking is also called hydrogen sulfide cracking, sulfide cracking, sulfide corrosion cracking and sulfide stress-corrosion cracking. The variation of the name is due to the lack of agreement in the mechanism of failure. Some researchers consider sulfide-stress cracking a type of stress-corrosion cracking, while others consider it a type of hydrogen embrittlement.

hydrogen sulfide

[H2S] An extraordinarily poisonous gas with a molecular formula of H2S. At low concentrations, H2S has the odor of rotten eggs, but at higher, lethal concentrations, it is odorless. H2S is hazardous to workers and a few seconds of exposure at relatively low concentrations can be lethal, but exposure to lower concentrations can also be harmful. The effect of H2S depends on duration, frequency and intensity of exposure as well as the susceptibility of the individual. Hydrogen sulfide is a serious and potentially lethal hazard, so awareness, detection and monitoring of H2S is essential. Since hydrogen sulfide gas is present in some subsurface formations, drilling and other operational crews must be prepared to use detection equipment, personal protective equipment, proper training and contingency procedures in H2S-prone areas. Hydrogen sulfide is produced during the decomposition of organic matter and occurs with hydrocarbons in some areas. It enters drilling mud from subsurface formations and can also be generated by sulfate-reducing bacteria in stored muds. H2S can cause sulfide-stress-corrosion cracking of metals. Because it is corrosive, H2S production may require costly special production equipment such as stainless steel tubing. Sulfides can be precipitated harmlessly from water muds or oil muds by treatments with the proper sulfide scavenger. H2S is a weak acid, donating two hydrogen ions in neutralization reactions, forming HS- and S-2 ions. In water or water-base muds, the three sulfide species, H2S and HS- and S-2 ions, are in dynamic equilibrium with water and H+ and OH- ions. The percent distribution among the three sulfide species depends on pH. H2S is dominant at low pH, the HS- ion is dominant at mid-range pH and S2 ions dominate at high pH. In this equilibrium situation, sulfide ions revert to H2S if pH falls. Sulfides in water mud and oil mud can be quantitatively measured with the Garrett Gas Train according to procedures set by API.

casing string

An assembled length of steel pipe configured to suit a specific wellbore. The sections of pipe are connected and lowered into a wellbore, then cemented in place. The pipe joints are typically approximately 40 ft [12 m] in length, male threaded on each end and connected with short lengths of double-female threaded pipe called couplings. Long casing strings may require higher strength materials on the upper portion of the string to withstand the string load. Lower portions of the string may be assembled with casing of a greater wall thickness to withstand the extreme pressures likely at depth. Casing is run to protect or isolate formations adjacent to the wellbore.

The following are the most common reasons for running casing in a well:

protect fresh-water aquifers (surface casing)

provide strength for installation of wellhead equipment, including BOPs

provide pressure integrity so that wellhead equipment, including BOPs, may be closed

seal off leaky or fractured formations into which drilling fluids are lost

seal off low-strength formations so that higher strength (and generally higher pressure) formations may be penetrated safely

seal off high-pressure zones so that lower pressure formations may be drilled with lower drilling fluid densities

seal off troublesome formations, such as flowing salt

comply with regulatory requirements (usually related to one of the factors listed above).

casing

well control

The technology focused on maintaining pressure on open formations (that is, exposed to the wellbore) to prevent or direct the flow of formation fluids into the wellbore. This technology encompasses the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to offset those pressures in a predictable fashion. Also included are operational procedures to safely stop a well from flowing should an influx of formation fluid occur. To conduct well-control procedures, large valves are installed at the top of the well to enable wellsite personnel to close the well if necessary.

drill pipe

Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.

liner

A casing string that does not extend to the top of the wellbore, but instead is anchored or suspended from inside the bottom of the previous casing string. There is no difference between the casing joints themselves. The advantage to the well designer of a liner is a substantial savings in steel, and therefore capital costs. To save casing, however, additional tools and risk are involved. The well designer must trade off the additional tools, complexities and risks against the potential capital savings when deciding whether to design for a liner or a casing string that goes all the way to the top of the well (a "long string"). The liner can be fitted with special components so that it can be connected to the surface at a later time if need be.

choke line

A high-pressure pipe leading from an outlet on the BOP stack to the backpressure choke and associated manifold. During well-control operations, the fluid under pressure in the wellbore flows out of the well through the choke line to the choke, reducing the fluid pressure to atmospheric pressure. In floating offshore operations, the choke and kill lines exit the subsea BOP stack and then run along the outside of the drilling riser to the surface. The volumetric and frictional effects of these long choke and kill lines must be considered to properly control the well.

BOP stack

A set of two or more BOPs used to ensure pressure control of a well. A typical stack might consist of one to six ram-type preventers and, optionally, one or two annular-type preventers. A typical stack configuration has the ram preventers on the bottom and the annular preventers at the top.

The configuration of the stack preventers is optimized to provide maximum pressure integrity, safety and flexibility in the event of a well control incident. For example, in a multiple ram configuration, one set of rams might be fitted to close on 5-in diameter drillpipe, another set configured for 4 1/2-in drillpipe, a third fitted with blind rams to close on the openhole, and a fourth fitted with a shear ram that can cut and hang-off the drillpipe as a last resort.

It is common to have an annular preventer or two on the top of the stack since annulars can be closed over a wide range of tubular sizes and the openhole, but are typically not rated for pressures as high as ram preventers. The BOP stack also includes various spools, adapters and piping outlets to permit the circulation of wellbore fluids under pressure in the event of a well control incident.

choke manifold

A set of high-pressure valves and associated piping that usually includes at least two adjustable chokes, arranged such that one adjustable choke may be isolated and taken out of service for repair and refurbishment while well flow is directed through the other one.

reservoir

A subsurface body of rock having sufficient porosity and permeability to store and transmit fluids. Sedimentary rocks are the most common reservoir rocks because they have more porosity than most igneous and metamorphic rocks and form under temperature conditions at which hydrocarbons can be preserved. A reservoir is a critical component of a complete petroleum system.

completion

The hardware used to optimize the production of hydrocarbons from the well. This may range from nothing but a packer on tubing above an openhole completion ("barefoot" completion), to a system of mechanical filtering elements outside of perforated pipe, to a fully automated measurement and control system that optimizes reservoir economics without human intervention (an "intelligent" completion).

production tubing

injection line

A small-diameter conduit that is run alongside production tubulars to enable injection of inhibitors or similar treatments during production. Conditions such as high hydrogen sulfide [H2S] concentrations or severe scale deposition can be counteracted by injection of treatment chemicals and inhibitors during production.

inhibitor

A chemical agent added to a fluid system to retard or prevent an undesirable reaction that occurs within the fluid or with the materials present in the surrounding environment. A range of inhibitors is commonly used in the production and servicing of oil and gas wells, such as corrosion inhibitors used in acidizing treatments to prevent damage to wellbore components and inhibitors used during production to control the effect of hydrogen sulfide [H2S].

chemical injection

A general term for injection processes that use special chemical solutions to improve oil recovery, remove formation damage, clean blocked perforations or formation layers, reduce or inhibit corrosion, upgrade crude oil, or address crude oil flow-assurance issues. Injection can be administered continuously, in batches, in injection wells, or at times in production wells.