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SEPARATION SYSTEMS

SEPARATION NEWS What’s Inside Protecting a NGL Pipeline................................. 2 Safety is a Priority............................................. 3 Amine Foaming Solution................................... 4 Alkylation Unit Optimization.............................. 5 Exploring Patagonia.......................................... 6 Produced Water 101........................................... 7 TX Produced Water Application........................ 8 Removing H2O from Diesel Fuel........................ 9 Brasil Offshore Exhibition............................... 10 Colombia; Becoming a Giant in Oil.................. 11 Plant Expansion - Amine Filter....................... 12 Rich Amine Filter Upgrade.............................. 13 Condensate in Unconventional Gas................ 14 Client Delight in Dubai..................................... 15 Malaysia and the Region.................................. 16 Rental Reduces Heat Exchanger Fouling....... 17

REDUCING SEPARATION ANXIETY FOR THE OIL & GAS INDUSTRY WORLDWIDE FILTRATION & PROCESS

volume ONE, spring 2013

www.pentairseparations.com


VOLUME ONE // SPRING, 2013

PENTAIR EQUIPMENT REMOVES CONTAMINATION FROM NGL pipeline particle filters (ProcessORs) and liquid/ liquid coalescing separators (LiquiSeps) to remove free water from NGL. It is critical that no particulate or free water contamination is present in the NGL product, PARTICLE/LIQUID SEPARATOR - ProcessOR® particularly before it is delivered to end-users at the fractionation complex. The client decided that the best way to make sure no contamination reaches the plant was to make sure no contamination could enter the pipeline at any of the numerous delivery points.

The core of our client’s pipeline project was a converted product pipeline that was previously operated by another company. The flow was reversed, the pipeline was cleaned up, new pump stations were installed, and metering stations for custody transfer of natural gas liquids (NGL) were constructed. These meter stations use Pentair equipment to remove contamination from NGL. The NGL pipeline runs from Kansas to South Texas. The pipeline was built to increase (NGL) transportation capacity from the Midcontinent to premium Texas Gulf Coast fractionation and petrochemical markets. The pipeline carries Y-grade NGL, and is connected to a number of gas processing plants and third-party NGL producers. It was a game changer for Midcontinent NGL values. This critical piece of midstream infrastructure will increase the value producers realize for their growing Rockies and Midcontinent NGL production through enhanced connectivity to the Gulf Coast NGL markets which provide premium pricing. The pipeline spans more than 700 miles, originating in Kansas and ending at in South Texas. The client elected to standardize on Pentair technology for this project because it offered a number of economic and operational benefits.

Pentair’s ProcessOR with Compax coreless liquid/particle filter technology uses permanent filter element center cores that are installed in the housing, and then allows the use of coreless replacement filter elements that provide for lower filter element costs, faster change outs, and greatly reduced disposal volume.

Pentair, working closely with their distributor in the Rocky Mountain area, Industrial Distributors, Inc., provided liquid

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VOLUME ONE // SPRING, 2013

IT’S NO COINCIDENCE THAT SAFETY COMES FIRST of our current energy customers operates a natural gas processing plant that processes approximately 300 million standard cubic feet of natural gas each day containing 12% hydrogen sulfide, one realizes the degree of safety that we must exercise in the field each day.

Safety. It’s the number one priority for our business. When we talk about the Pentair Integrated Management System (PIMS) the five primary points that start every discussion of our business are SQDCC: Safety, Quality, Delivery, Cost and Cash. It’s no coincidence that Safety comes first. Our first priority is that every Pentair team member enjoys a safe work environment and returns home safely at the end of each day. Maintaining a safe work environment presents some unique challenges in the Energy industry. Not only are our customers engaged in operations that inherently involve risk (e.g. – high temperature, high pressure operations), but often the very oil, gas and hydrocarbon products produced are hazardous. Frequently, natural gas and crude oil at the wellhead, contain significant levels of contaminants that require removal prior to use heating our homes, providing power to our cities and cooking our meals. The removal of these hazardous contaminants takes place in the processing plants that form our energy customer base.

To effectively manage the safety risks in our business, we invest a tremendous amount of resources in training and personal protective equipment. Our sales personnel and field engineering staff are required each year to undergo an industry standard safety program through a regional industry safety council. In addition to general safety in process environments, we undergo hydrogen sulfide awareness training. We also empower each of our personnel to refuse to engage in any activity within our customer sites which they believe to represent an unreasonable safety risk. Frequently operations that have high levels of hydrogen sulfide also require additional site specific training before allowing us access to their process units. Those who may encounter hydrogen sulfide in their day to day activities also require annual respirator training, respirator fit testing, medical clearance and supplied air training (SCBA). Additionally, all team members who enter process plants where hydrogen sulfide is present must wear a personal hydrogen sulfide monitor at all times. The monitor creates a continuous audible alarm, a visual strobe and a vibrational alarm when hydrogen sulfide levels greater than 5 ppm are present and a secondary alarm if those levels exceed 10 ppm. The alarm allows early detection of elevated levels of hydrogen sulfide and typically results in evacuation of the area. In addition, plants where hydrogen sulfide are present have distributed area alarms for hydrogen sulfide detection and automatic shut-down procedures in the event of a unit alarm for hydrogen sulfide.

Most often the contaminant naturally present in crude oil and natural gas which presents the greatest concern is hydrogen sulfide. Hydrogen sulfide occurs naturally in many petroleum fields due to the presence of sulfate reducing bacteria deep underground. Rather than relying on oxygen for respiration like we do, these bacteria reduce sulfates naturally present in the rocks to generate cellular energy. The bacteria then release hydrogen sulfide as a byproduct which accumulates in reservoirs and is produced along with the oil and gas. Hydrogen sulfide has the characteristic odor of rotten eggs. It’s not the unpleasant odor, however, that is the primary concern in hydrocarbon processing. Hydrogen sulfide is a poison. Additionally it is flammable and corrosive. Fortunately, hydrogen sulfide has a very low odor threshold with concentrations of as little as 1 ppm being easily detected by the nose. Unfortunately, prolonged exposure or concentrations above 100 ppm paralyze the olfactory response, making the nose an unreliable detector of hydrogen sulfide. The permissible exposure limit for most of our customers is deemed to be 10 ppm. Levels above 100 ppm are considered immediately dangerous to life and health by NIOSH standards. This is particularly important as concentrations of 300 ppm may render a person unconscious and concentrations of 600 ppm may cause immediate death. When one considers that one

Good engineering practices minimize the potential for exposure. We couple that with a strong safety culture; Comprehensive personal safety training, a focus on awareness and proper protective equipment are the cornerstone of our safety measures. This ensures that each of our field personnel are able to carry out their tasks in a safe manner and allow us to continue to serve our customers and grow our business. Our commitment to safety is our first priority. 3


VOLUME ONE // SPRING, 2013

PENTAIR TECHNOLOGY SOLVES AMINE FOAMING HRT and ultisep BENEFITS gas processing facility

A 50 MMSCFD gas processing facility in the Rocky Mountain Region was having challenges with foaming in their amine process. The plant was processing sour gas from the field and feeding it to an amine contactor for acid gas removal prior to the cryogenic NGL recovery process. The foaming excursions were intermittent and attributed to the presence of hydrocarbons in the amine. The plant contacted us through our authorized distributor after experiencing recurring amine upset episodes and having challenges in maintaining required flow rate through the plant. It was confirmed by their amine vendor that there was significant hydrocarbon ingress in the solvent system. Pentair deployed a rental HRT® vessel to install downstream of their rich amine filters to remove the liquid contaminants and restore the amine quality.

Pentair field services were on-site to conduct slip stream pilot testing to verify the gas quality downstream of the UltiSep® aerosol separator. The test unit was evaluated downstream of the UltiSep® to determine whether

Pilot UltiSep test unit and the compressor lube oil that was collected from the bypass line.

This was a clear indication that the valve on the bypass line around the UltiSep® was leaking. Moving forward the plant replaced the bypass valve and continued running the HRT® on the amine to mitigate the hydrocarbon that is currently in their amine. Since the root cause of the amine fouling was traced back to their bypass line, they will operate the HRT for a few more weeks to restore the amine purity.

HRT (left) on the amine process and UltiSep (right) upstream of the amine contactor.

Treated Gas

Acid Gas

Lean Amine

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Upon operating HRT® for several months, the plant continued to struggle with foaming and hydrocarbon ingress. Pentair field services were contacted as the plant suspected that there may be challenges with the operation of their UltiSep® which already sits upstream of the amine contactor. It appeared they were continuing to have compressor lube oil carryover into their amine. A simplified process flow diagram of the plant can be referenced in Figure 1 to the right.

the lube oil was making its way into the amine. After testing for 24 hours it was concluded that the UltiSep® vessel was performing well and was not carrying contaminants downstream. The same test was subsequently run downstream of where the bypass line tied into the piping downstream of the UltiSep®. After testing for less than 12 hours, a significant quantity of oil contaminants were drained from the sight glass of the test unit as pictured below.

8 1

Rich Amine

Sour Gas

Rich Amine Filter Vessels

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1

6 4

3 1

ULTISEP SEPARATOR

2

AMINE CONTACTOR

Flash Tank

5 RICH AMINE PREFILTER 6

3 BY-PASS VALVE 4 AMINE FLASH TANK

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RICH AMINE HRT SEPARATOR

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REGENERATOR TOWER

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LEAN AMINE PREFILTER,CARBON FILTER, POST CARBON FILTER

Figure 1 – Process Flow Diagram shows the various filter vessels on the amine system

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VOLUME ONE // SPRING, 2013

virtually 100% removal of free and emulsified water contaminant ANALYSIS LEADS TO UNDERSTANDING; LEADS TO RESULTS

THE PROBLEM A Northeast Refiner has experienced ongoing challenges associated with productivity losses, deisobutanizer tray fouling and reduced system throughput at the Alkylation Unit due to high levels of salt saturated water contamination bypassing the existing D-8 coalescing vessel (vane pack/mesh pad vessels). A recent deisobutanizer fouling event was estimated at a loss of +$200,000 in productivity due to an unplanned shutdown.

coalescer with the second set at the Outlet. The systems operated with no measured differential pressure across either the Particle Separator or the Liquid Separator devices during the test. The Alkylate flow rate was ~24,000 Barrels per Day during the first week of testing. During the second week (November 12th) the Alkylate flow rate was increased to ~37,000 BPD. Using the data from the operation log and the measured water drained from the pilot vessels, the water removed ranged between 130 mls to 1420 mls on the inlet side at a flow rate of 24,000 BPD (representing the free water seen at the D-8 coalescing vessel). As the flow rate was increased up to 37,000 BPD the liquids removed ranged from 200 mls to 2,140 mls (at the D-8 inlet). On the Outlet set of vessels, the water separation efficiency associated with the LiquiSep system ranged from 80 mls to 1,300 mls (at a flow rate of ~24,000 BPD) and 220 mls to 3,350 mls (up to ~37,000 BPD) representing virtually 100% removal of free and emulsified water contaminant from the stream.

ABOUT THE CONVENTIONAL TECHNOLOGY Vane pack/mesh pad vessels (ex. D-8 coalescer) are considered relatively low efficiency separators with an average liquid separation performance ranging from 10% – 40%. In general, conventional systems separate bulk liquid, typically 200um and larger. When systems contain high sheering devices upstream (ex. pumps, valves, mixers, etc.), the largest concentration of liquid droplets tends to be in the range of 50um and less (similar to tobacco smoke), resulting in a high level of liquid contaminant bypassing vane pack/mesh pad devices and contributing to operating challenges downstream (ex. deisobutanizer tray fouling). In other words, the effluent from these high sheering devices often contain free water levels of 300 ppm to several thousand ppm that go untouched.

RESULTS Based on the data collected at the outlet of the D-8 coalescer, it averaged an overall removal efficiency of approximately 20%, equating to 80% of the free water bypassing the D-8 vessel and being removed by the LiquiSep system. Coupling that performance upstream and downstream of the D-8, the performance demonstration clearly proves the technologies ability to remove virtually 100% of the free water down to the solubility limit for promoting enhanced system reliability and improved deisobutanizer performance.

ABOUT PENTAIR’S LIQUISEP LiquiSep is designed to effectively separate virtually 100% of the free and emulsified submicron to micron water droplets mitigating premature system shutdowns and fouling of vital equipment downstream (ex. deisobutanizer), while simultaneously increasing system throughput and process efficiency. The following technology evaluation performed at the Alkylation Unit will assist in supporting the high efficiency separation achievable through the implementation of a LiquiSep system.

Provided below are pictures associated with the LiquiSep upgrade performed at the Coalescer vessel.

METHODS OF TESTING AND ANALYSIS Two Pilot Systems were used for this study. One (Inlet) was connected prior to the D-8 Unit. The second set (Outlet) was connected downstream of the D-8 Unit. The pilot systems effluents were routed back to a bleed valve on the outlet of the Control Valve. Flow through the pilot systems were regulated between 1.6 to 3 gallons per minute.

From left to right – 1) coalescer vessel with mesh pad removed, 2) upclose picture of mesh pad illustrating the wide open media structure leading to high levels of bypass, 3) completed, Pentair Liquisep upgrade (flows from inside to out)

One set of vessels was installed at the Inlet side of the D-8

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VOLUME ONE // SPRING, 2013

Pentair Explores the Patagonia Pentair aids in Argentina’s development of unconventional reserves

A great man once said, “If you ain’t first, you’re last…” This is what came to my mind when I was asked to speak as a subject matter expert at the Infocast Water Management for Shale Plays, Argentina Conference earlier this year.

much water this really is, think of a very larger river (Rio Negro is the largest in the area). The water required for a SINGLE well is equivalent to approximately 20 seconds of that river’s full flow. The required well density for optimal

The focus of the conference was aimed at helping Argentina’s producers and other interested parties understand the ins and outs of water management as it relates to developing unconventional oil and gas fields. In the U.S., unconventional production has been booming for a number of years now, making Pentair a late contender in an already maturing (although still quickly growing) market for water management. Don’t count us out, but this does make things a bit more difficult as other companies have claimed their share of the market. That being said, I jumped at the opportunity to visit Argentina and get Pentair’s flag in the ground as an expert in the field, and the chance to get our technology considered from day zero of the ramp up of development. I shared my experiences regarding water treatment in oil and gas worldwide- specifically trends in centralized vs. mobile treatment schemes and the factors to be considered when developing a water treatment scheme.

profitability is 5 wells per km^2. Needless to say there is going to be a lot of water used. The Neuquen lies in Northern Patagonia, and as seen in the graphic, is a desert environment. Water scarcity will be a challenge to overcome. Effective treatment of water for reuse is going be critical to successfully produce these reserves, and therefore critical to the future of the Argentine economy. Pentair has taken the first step to address this challenge and bring value to our new potential customers. The region does also possess conventional oil and gas reserves, which have been producing for the past 20+ years. While in Beunos Aires, I was fortunate to be invited to a meeting on-site in Neuquen, at a local producer’s 100,000 barrels per day produced water treatment facility, shown below. Working with this customer, we have begun to have a very clear picture of the costs and status quo of produced water treatment in the region, as it relates to conventional oil and gas production. It has been made clear that there are many opportunities for our HRT (Hydrocarboon Recovery Technology) to be used immediately in the region, as well as into the future during the ramp up of unconventional production.

The majority of Argentina’s recently verified unconventional reserves lie in the Neuquen basin shown in the graphic. This area covers approximately 120,000 km^2 and contains almost 400 trillion cubic feet of technically recoverable shale gas. YPF, the nationalized oil and gas entity of Argentina is aiming for a mind-blowing 35 Billion USD investment between now and 2017 to ramp up production of these reserves and increase refining capacity, focusing on this region.

Expect to hear more good news soon on the progress of Pentair Produced Water Treatment in Argentina.

In order to economically tap these unconventional reserves, the producers of the region will need to make efficient water management a top priority. It can take up to 5 million gallons of water to drill and frac a single well. To get an idea of how 6


VOLUME ONE // SPRING, 2013

PRODUCED WATER 101 INDUSTRY CHALLENGES AND PENTAIR SOLUTIONS

Drilling and extracting Oil & Gas from beneath the Earth’s surface supports our ever growing need for energy, however, it also poses significant water challenges for both the industry and for mankind. The challenge is increased by the ever expanding process of hydraulic fracturing. Hydraulic fracturing is the fracturing of various rock layers by a pressurized liquid; typically 95% water mixed with sand and chemicals. Induced hydraulic fracturing or hydrofracturing, commonly known as fracking, is a technique used to release petroleum, natural gas (including shale gas, tight gas, and coal seam gas), or other substances for extraction.

In many parts of the world, water is a scarce resource. And in parts of the world where water is abundant, deep well injection is believed to have a negative environmental impact and is widely unpopular. Continuous concerns over drinking water contamination, water conservation and other environmental impacts are changing the game, refocusing the industry on produced water treatment, recycle, and recovery. Pentair’s product portfolio strikes at the heart of the produced water treatment challenge. Pentair’s Hydrocarbon Recovery Technology - HRT® offers proven solids removal coupled with hydrocarbon recovery performance to less than 5 ppm, while eliminating the need for expensive chemical additives and storage tank capacity. With hydrocarbon recovery efficiencies of 99.98%, HRT® produces a sellable hydrocarbon product which balance or even outweigh operating costs and capital investment.

Millions of gallons of water can be needed to hydraulically frack a single well and typically over 75% of the water used in fracking, remains in the ground. When a well is placed into service for the first time, approximately 10% to 25% of the hydrofracturing fluid comes out, mixed with hydrocarbons, drill cuttings, and other contaminants. This liquid, known as “Flowback Water” typically lasts for 3 to 4 weeks, with most of it coming in the first 7 to 10 days. The flowback water is very high in suspended solids and contains chemicals, metals, and other contaminants that are extremely difficult to treat. Flowback water is typically disposed of by deep well injection at approved salt water disposal wells.

Pentair’s X-Flow® Ultrafiltration (UF) Technology is an excellent filtration technology for the polishing of Produced Water following the HRT® to meet difficult discharge specifications, or as a pretreatment to Reverse Osmosis. The hollow fiber membranes operate at 90% to 98% recovery, and effectively provides product water that meets quality specifications of <3.0 SDI, <0.1 Turbidity, and Total Hydrocarbon Content of Non-Detect. The addition of Pentair’s Reverse Osmosis (RO) Technology as a final treatment step provides Total Dissolved Solids (TDS) reduction, allowing Produced Water to be safely discharged back into the ground water, or recycled for other uses such as irrigation or farm use.

Over time, as the well continues to flow, a steady flow of hydrocarbons and formation water (water found naturally in the earth) comes from the well. The hydrocarbons are separated at the surface with the remaining fluid being “Produced Water”. Produced water continues to flow for the life of the well. The treatment and disposal of Produced Water represents the single largest expense of extracting Oil & Gas to the industry. It also represents a significant opportunity for water recovery.

While drilling and extracting Oil & Gas continue to move us forward into the future, Pentair’s complete portfolio of products continue to ensure that Produced Water can be recovered, treated, and reused to meet the demands of tomorrow.

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VOLUME ONE // SPRING, 2013

MAKING A SPLASH FOR A SOUTH TEXAS OILFIELD PRODUCED WATER APPLICATION PROVES EFFICIENT AND EFFECTIVE

Produced Water is a hot topic for companies (including ours), especially overseas. We are on the brink of getting things off the ground – or should I say, separate out of the water – in an old oilfield in South Texas. Our client has agreed to field trial of our HRT® (Hydrocarbon Recovery Technology), to clean up the produced water so that their technology can work by mid-June of this year. In this case, the old field is producing 15-20% of what it used to in the way of Barrels of Oil per day (BPD). The owners of the field ‘flood’ the formation with water where the oil is underground, to increase the pressure to force out the valuable crude oil and increase production. The oil comes out with the produced water and is hauled away. The client has a technology that enhances recovery as well, which requires less water; however, when oil contaminates the water, their technology is impaired. Pentair is providing a particulate removal technology, Compax® elements within our ProcessOR® vessel, to protect HRT® as it separates the oil from the produced water. Not all the oil can be skimmed off and the water is valuable and needs to be reused. As seen below, we have effectively separated the oil from the water for our client to reuse:

The challenge in this situation is that the field in play has a salinity twice the amount of sea water and is so corrosive that 316 stainless steel vessels cannot hold up in the environment. This is not an unusual situation. With the help of talented engineers we had two vessels made to withstand the challenge. Very special glass flake lined vessels with high phosphate electroless nickel plated hardware internals will make this produced water venture a successful one for the client!

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VOLUME ONE // SPRING, 2013

UNDERSTANDING LEADS TO PROCESS OPTIMIZATION A Midwest US refiner using Pentair’s LiquiSep® technology to remove H2O from a 43 BPD diesel fuel stream began to experience the challenge of premature life of downstream salt driers (estimated operational burden of $100K per year). By analyzing their process, we came to understand that the refiner made process feed changes upstream. This was causing more solid contaminant to be introduced to the liquid-liquid separator (LiquiSep®), which in turn caused dP (differential pressure) to spike often and create “bypass” by means of the tube sheet pressure relief valve set to open linearly from 10-30 dP. The separator (with operating conditions of 200 PSIG max; 105 degrees F max; S.G. of .87; viscosity of 1.74 cP) was now requiring element change-outs almost monthly, resulting in $40K new annual costs (refer to the left side of the below refiner-provided chart).

WITHOUT A PRE-FILTER

PROCESSOR, SOLID-LIQUID SEPARATOR SKID SERVING AS PRE-FILTER

To quickly remedy the situation Pentair provided the refiner a dual 36” O.D. ProcessOR® (particle separator) rental skid to act as a “pre-filter” to the LiquiSep® separator. The rental would validate the optimization measure before capital would need to be invested. We shipped the skid to the refiner’s site and he activated it. As depicted on the right side of the chart (right), the dP spikes in the separator were eliminated and the element life was increased to nearly 7 months, as a result of the skid’s impact on the process. And, the downstream salt drier operational burden disappeared (eliminating the $100k operating cost plus the additional $40k of element change outs), delighting the refiner. After 8 months of consistent, satisfactory service, the refiner took steps to permanently incorporate the skid and ordered it for purchase.

DUAL PROCESSOR SKID

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LIQUISEP


VOLUME ONE // SPRING, 2013

Synergy between Energy and Valves & Controls on Brasil Offshore 2013 Leader segment event and 3rd largest in the world, Brazil Offshore 2013, that will take place from 11th to 14th June in Macaé, city responsible for more than 80% of Brazilian offshore operating, will count with the Separation Systems and Valves & Controls team, presenting Pentair technologies to the sector. To the Separations Systems team, the event will be a great opportunity to present HRT as a Produced Water treatment alternative. Held every two years, with more than 50,000 visitors, the event allows professionals to seek new exploration and production technologies, discuss new ideas and find solutions that allow them to see the potential of the Brazilian market offshore.

Where the Offshore sector does business June 11-14, 2013

Sinergia entre Energy e Valves & Controls na Brasil Offshore 2013 Evento líder do segmento e 3º maior do mundo, que ocorrerá de 11 a 14 de Junho em Macaé, cidade responsável por mais de 80% da exploração Offshore do Brasil, contará com a presença dos times de Energy e Valves & Controls, apresentando as tecnologias da Pentair para o setor. Para o time de Energy, o evento será uma ótima oportunidade para apresentar o HRT como uma alternativa para o tratamento de Águas Produzidas. Realizado a cada dois anos, com mais de 50.000 visitantes, o evento permite que profissionais busquem novas tecnologias de exploração e produção, debatam novas ideias e descubram as soluções que os permitam observar o potencial do mercado Offshore brasileiro.

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VOLUME ONE // SPRING, 2013

COLOMBIA SE ESTA CONVIRTIENDO EN UN GIGANTE PETROLERO EN AMERICA LATINA Colombia, es hoy en día uno de los países más promisorios en los mercados de inversión del mundo en cuanto a exploración y producción de petróleo se refiere. Hoy día, es el cuarto productor de petróleo en América Latina, detrás de Venezuela, Brasil y México, Colombia contabiliza dos billones de barriles de crudo en reservas probadas en el 2012, lo cual significa unos siete años de producción activa.

con ECOPETROL, que es la industria petrolera del estado colombiano. Hoy, ECOPETROL no controla la exploración y producción de hidrocarburos, permitiendo a los inversores extranjeros poseer el 100% del contrato. Como resultado, ECOPETROL opera ahora más como una empresa petrolera tradicional, compitiendo con compañías privadas. Adicionalmente, los inversores extranjeros tienen los mismos derechos y beneficios que cualquier inversor nacional, trayendo esto como consecuencia, mayor cantidad de concesiones de exploración otorgadas.

La producción de petróleo colombiano, se incremento desde el 2008 debido al incremento en la exploración y desarrollo de esta industria. En el 2011 habían 34 operadoras petroleras diferentes explorando en Colombia. Las áreas de exploración se incrementaron de más de 100 millones de hectáreas en el 2011, en comparación con las 12,5 millones de hectáreas del 2.003

La industria colombiana de (E&P) petrolera, también dá beneficios especiales de cambio monetario, permitiendo a las empresas de gas y petróleo, recibir pagos en moneda extranjera entre ellos o con otros países.

Para promover una mayor exploración petrolera, el gobierno colombiano organizó una subasta de derechos de exploración, llamada “Ronda Colombia 2012”, promovida el año pasado por la Agencia Nacional de hidrocarburos.

El único requisito es que los recursos en moneda extranjera provengan de beneficios de las operaciones realizadas en el país. Además, no hay obligación de rembolsar al mercado financiero, las divisas obtenidas en moneda extranjera.

Durante el 2012, 115 bloques fueron ofertados, de los cuales 31 incluían hidrocarburos no convencionales tales como petróleo y gas de pizarra o esquisto (shale gas and shale oil), gas de arenas profundas/compactas (tight gas) y gas en capas de carbón (coal bed methane). Exxon Mobil Corp, Royal Dutch Shell PLC y Anadarko Petroleum Corp. (Texas), se encontraron entre las ganadoras. Durante la subasta, a los ganadores les fueron asignados 49 de los 115 bloques petroleros convencionales y 5 de los 31 bloques no convencionales.

Durante los últimos 10 años, bajo el gobierno del Presidente Álvaro Uribe, las fuerzas armadas colombianas, incrementaron la estabilidad política, la seguridad y el crecimiento económico, en la mayoría de las áreas urbanas del país. Ahora, bajo la presidencia de Juan Manuel Santos, han dado un paso más, al comenzar las negociaciones de paz con las Fuerzas Armadas Revolucionarias de Colombia (FARC) desde octubre del 2012. La mayoría de los colombianos apoyan estas negociaciones, que por ahora van por buen camino.

El verdadero catalizador del boom petrolero colombiano, ha sido las reformas dentro de las instituciones que controlan la industria del petróleo y el gas, los términos contractuales a las empresas explotadoras y las remuneraciones financieras. Específicamente, la nueva figura legal colombiana, permite a los inversores poseer el 100% de la participación en los proyectos petroleros. En el pasado, los contratos exigían igual participación

Sin lugar a dudas, el proceso de paz aumentará las esperanzas económicas de la industria petrolera, la cual ha sido blanco de las FARC, trayendo como consecuencia un aumento en la exploración y producción en el futuro.

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VOLUME ONE // SPRING, 2013

EAST TEXAS UPGRADE WITH COMPAX AMINE FILTER UPGRADE IN NEW PLANT

A client in East Texas has been going through expansions to accommodate increased gas volumes from local gathering systems. The increased gas volumes are direct result of increased drilling activity in the area. The majority of the drilling in the area is for oil with the wells producing roughly 90/10 ratio of oil to gas. Even though the gas component is only 10 percent of the extracted hydrocarbon, the local gas processor does not have the capacity to accommodate these increased volumes. This East Texas gas processor has added a new, standalone plant to handle more flows out of the east side of the area. In addition to increasing volumes needing to be processed, there has been a push to extract an increasing amount of natural gas liquids (NGLs) from the gas flowing from the wellhead. By extracting these NGLs, the gas processors are able to extract more value from the raw natural gas they

are processing. In order to pull more NGLs out of the gas, they have to treat the gas stream to remove more carbon dioxide, an impurity. Two of the new gas treatment plants installed in the area are to remove more carbon dioxide at existing facilities. They have built these directly next to existing plants to increase NGL extraction capabilities. Pentair has provided amine system particulate separation (ProcessOR with Compax elements) for many years at the existing facility. This proven performance led the client back to Pentair to upgrade the vessels in the new plant. Pentair Field Service personnel were onsite to take exact measurements of the vessels and propose a design for upgrading the system. The vessel upgrade utilizes our Compax速 coreless technology. The upgrade will take no longer than a typical element change out (4 hours maximum) to keep the facility running smoothly, with no downtime. We were able to provide continued performance on new equipment with little-to-no change in operations of the existing plant.

AMINE CONTACTOR

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VOLUME ONE // SPRING, 2013

Rich Amines Upgrade Fractionation Gas Plant PENTAIR’s HIGH EFFICIENCY COMPAX

A Louisiana NGL fractionation plant was facing challenges with their rich amine filters. Due to the inefficiency they were experiencing, they had a plant upset and had to change out 239 elements 11 times over a period of 4 days. These were 2.5” x 30” string wound filters, a conventional filter used in the industry but extremely inefficient. Prior to the upset, normal element change outs were every 10 days.

from 239 to 35. The existing, conventional configuration of 239 string would elements had a total of 570 sq. ft. of element surface area. By utilizing our Compax® elements, it reduced the number of elements to 35 and brought the total sq. ft. of element surface area to 4,270. That is a 7.5 times increase in the surface area which creates longer online life and more efficient separations.

Through discussions with the plant manager, we came to understand their issues and the Pentair team went on-site and took gravimetric samples and vessel measurements. We followed with a recommendation of upgrading one of their two amine filter vessels with a plan to upgrade the second at a later date. The upgrade was to include a reengineered tube sheet and our Compax® coreless elements and semi-permanent cores for particle/liquid separation.

The plant is now running at least 30 days before change outs and they have also acknowledged a much cleaner rich amine product with zero bypass issues. This creates a dramatic, positive impact on operational costs and immense value by producing quality product in their rich amine. This opportunity and the performance associated with it has led to discussions around our HRT® (Hydrocarbon Recovery Technology), which was purchased one month ago.

This upgrade option reduced the entire element count

BEFORE (left), 239 slots for string wounds and AFTER (right), Pentair’s Compax elements

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VOLUME ONE // SPRING, 2013

Condensate Challenges with Unconventional Gas OPTIMIZING THE PROCESS TACKLES THE CHALLENGES

There are tons of unconventional gas plays popping up around the United States; these unconventional plays are producing gas, oil and “condensate”. This condensate is being collected from the field and stabilized in gas treating and processing facilities. There have been a whole host of challenges associated with the stabilization process; fouling of heat exchanging equipment, fouling of stabilizer columns, poor feed quality (solids and chemicals), chloride contamination, and downstream product specification challenges. Pentair’s ProcessOR® and LiquiSep® technologies, for particle/liquid and liquid/liquid separations respectively, can be utilized to address these challenges and provide an optimal operational unit with no contamination infiltrating products and downstream processes. Below is a simplified process flow diagram (PFD) of the stabilization unit and where our ProcessOR® and LiquiSep® technology would be placed to optimize the process. We recently ran a full flow pilot unit at a mid-continent gas processing facility. This facility was operating with a flowrate of 1,750 bbl/ day and 275 PSIG. The plant was experiencing heat exchanger fouling on the reboiler of the stabilizer along with water ingression. To top it all off, chlorides were being carried overhead, back to the front of the plant where it was causing accelerated degradation of the amine for acid gas removal. The LiquiSep® (left) and ProcessOR® (right) were recently placed into service, illustrated in the top two pictures below.

Through the first month of service the plant experienced extreme slugs of solids that would have otherwise plugged the downstream equipment. But with a Pentair ProcessOR® in place, it protected the downstream equipment from having to be shut down and cleaned out; keeping the unit operating during the influx of solids. The bottom two pictures, right, show the bottom of the vessel completely covered in solids. The challenge with the upset was the plant experienced short on line life from the extreme influx of solids. After the upset conditions passed over, the plant went into stable operation and have seen on line life of up to two to three months before needing to changeout filter elements. Providing the customer with an optimized solids removal solution and providing effective online life aligned with the customers operational goals. Pentair has been in works with other facilities to work on their stabilized product to provide color removal with our new IntelliSep technology. This technology makes use of a medium that is capable of absorbing both organic and particulate, contributing to off spec color product downstream of stabilization. With these technologies Pentair looks to provide optimized condensate and stabilization units to help operators manage their plant. 14


VOLUME ONE // SPRING, 2013

MIDDLE EAST GAS UPGRADE BEYOND BEING A VENDOR; BEING A PARTNER

Our client has been in operation for 30 years. The plant receives the produced gas from on-shore and off-shore fields around Dubai. The company is also a major producer of MTBE in the region and the only one in the Emirate. MTBE is a key additive used in Gasoline for raising the Octane number, and this places them in a very significant role as the source of this important input in the manufacture of an ever increasing gasoline demand. Pentair supplied several solid/liquid (ProcessOR) and gas/liquid (UltiSep) separation vessels when the plant was originally established. Over the years the plant has seen a gradual increase in throughput and last year, our companies started communicating on the need to add additional vessels to cope with the increased capacity. There were budget constraints for capital expenditure in the short term and they were also facing the requirement of staying in maximum production mode to cope with demand. In view of this, the plant was considering investment in only one additional vessel, while living with bottle necks in other parts of the plant. After reviewing the existing designs, our Nex-Sys Systems Engineering group came up with a proposal to upgrade the capacity of the most critical vessel by 35%, without the need for any hot work or extended down time. With the addition of a new vessel and the upgrade in capacity of a second one, de-bottlenecking in an important process area could be achieved. This proposal was accepted and the order was placed for new hardware as well as an upgrade. Pentair customer service, manufacturing and applications engineering teams got together to ensure a quick turnaround on this project. The ordered new vessel and upgrade materials were delivered to the plant site by the promised scheduled date. We installed the cores and put the upgraded vessel back on line to complete the project execution. This was not the most complicated upgrade for us, but for the client, it meant a great deal and allowed for capacity expansion at a difficult time. The client was delighted by the process optimization carried out by Pentair and the Senior Management expressed their satisfaction. Having pleased a loyal customer through our continuous engagement and response, we are excited to participate in several future opportunities within this plant.

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VOLUME ONE // SPRING, 2013

MALAYSIA WIN WILL BREED FUTURE SUCCESS IN THE REGION REDUCTION OF PARTICULATE AND WATER CONTAMINATION FROM NATURAL GAS STREAM

A major international petroleum producer extracts natural gas off the coast of Terengganu state in the north-east of peninsula Malaysia. Hydrocarbon gas and condensate from offshore platforms are sent via a subsea pipeline to an onshore oil and gas terminal. They pass through slug catchers where the gas is separated. The remaining condensate flows to a separator where it is metered and exported. A looped pipeline is used for temporary storage when a sizable amount of liquid is received. This pipeline had been de-rated due to corrosion and water contamination. The water needs to be removed to ensure that the life of the looped pipeline is prolonged.  Furthermore, there is also sludge formation which can plug instruments. Pentair proposed and won a bid for the reduction of particulate and water contamination from the condensate stream. We utilized two of our high performing technologies to accomplish this. ProcessOR to remove particulate contaminant and LiquiSep to separate free dispersed and emulsified droplets from the primary fluid. Both vessels were horizontal, 48” OD with the ProcessOR housing 46 of our Compax coreless elements and 28 Apex elements in the LiquiSep. This is the first major hardware and element win in Malaysia in the oil & gas segment for Separation Systems. It will act as a valuable sales reference moving forward and upon successfull execution of this project, there will be similar projects as the focus on natural gas increases in the region.

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VOLUME ONE // SPRING, 2013

Low Sulfur Diesel Fuels Opportunity WISCONSIN REFINER PRODUCES a full range of transportation fuels The refiner processes Canadian and North Dakota crude oil from the Bakken formation beneath the Williston Basin. The refinery produces a full range of transportation fuels, including heavy #6 fuel oil for many of the freighters operating on the Great Lakes.

Upon commissioning of the vessel, bottle samples were collected upstream and downstream of the separator and sent to Pentair’s Star Labs for further analysis. The results of the sampling can be referenced in the following images.

A

In the past, production of diesel fuel went quite smoothly, requiring only infrequent cleaning of the heat exchanger (HEX) serving the hydrotreater. Then, when ultra-low-sulfur diesel (ULSD) standards came into play later in 2006 for on-road vehicles, the refinery committed to make all of its diesel to the ULSD standard. This requires their hydrotreater to operate approximately 100°F hotter (around 715°F) in order to keep sulfur under the 15 ppm limit, making it critical that the HEX function very efficiently.

B

The inlet (A) and outlet (B) gravimetric membranes used to measure the solids concentration at a 100x magnification.

An unintended result of the increased hydrotreater operating temperature has been increased HEX fouling, which progressively forces throughput to be reduced. In order to restore HEX efficiency and maintain their 175 GPM run rate, they had been removing and cleaning the four 30” x 12’ HEX tubing bundles every 8 weeks. Each cleaning event takes the diesel hydrotreater down for a minimum of 36 hours, and involves considerable labor to remove, clean, and re-install. The opportunity cost of lost diesel production during the 36 hours equates to approximately $1 million.

We had the opportunity to be on-site for the first filter change-out, which was done just 13 days after the unit was installed. As depicted in these photos, it was very apparent that the ProcessOR® was removing significant amounts of contaminants.

The sampling results show that the rental vessel was able to provide significantly better fluid quality and reduce the contaminant to the heat exchangers. As a result of this vessel going into service, the plant was able to run continuously for three solid months to make their planned shutdown or “turnaround”. In the past they would have had to take a heat exchanger offline for cleaning. The plant will continue to evaluate the effectiveness of the rental equipment. And our next step will be working with them to optimize the operational costs of the ULSD.

In an effort to reduce the heat exchanger fouling and increase hydrotreater uptime, the refinery elected to install a Pentair 36” ProcessOR® vessel from our rental fleet. The rental unit went on-line mid-month. Analyses were performed on gravimetric samples collected from the raw diesel feed (coming straight off the crude unit), and determined the total suspended solids (TSS) concentration was about 12 mg/L. These were comprised primarily of carbon and oxygen, with smaller amounts of iron & sulfur (likely from corrosion, pipe scale, etc.). These results aligned with the heavy hydrocarbon, shoe polishtype of material routinely found contaminating the HEX.

Elements after 13 days in service having reached the change out differential pressure. The image bottom left shows the shoe polish contaminant that was present on the elements containing hydrocarbon and iron sulfides.

LEFT - Rental Vessel on DHT feed to heat exchanger. RIGHT - Inlet and outlet of the DHT rental filter after installation

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VOLUME ONE // SPRING, 2013

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Pentair Separation Systems Newsletter - Spring, 2013  

Separation News gives you customer stories around optimizing filtration & separation processes with high performance technologies by Pentair...