Wednesday, May 23, 2018

Pushing Out the Oil with Conformance Control

The growing problem of water production and a stricter environmental enforcement on water disposal are forcing oil companies to reconsider conformance control - the manipulation of a reservoir's external fluid drive to push out more oil and less water. The technical challenges range from polymer chemistry to detailed knowledge of reservoir behavior. 

By late 1984, after several years' research, Marathon Oil Company laboratories in Littleton , Colorado, USA established a new polymer-gel system to block high-permeability channels within a reservoir and improve oil recovery. Previous attempts using less sophisticated chemistry had failed because the chemicals had become unstable at reservoir conditions and also were partially toxic. During the next three years, Marathon performed 29 treatments with the new system in nine of its fields in Wyoming's Big Horn basin. Fourteen treatments were in carbonate formations, and 15 were in sandstones.

The greatest success occured when injection wells were treated. The Big Horn reservoirs are known to be naturally fractured and the injected polymer-gel system most likely filled much of the fracture system between injector and neighboring producer.  This would force subsequent water drive to enter the matrix rock or fractures untouched by the treatment and push out oil. In many cases, a declining production in the neighboring producer was dramatically reversed, staying that way for several years.

Overall, the 29 treatments yielded 3.7 million barrels more oil than if the treatment had never been done, at a total cost of just $0.34 per barrel. Considering the price of oil at the time ranged from $30 to $24, Marathon had got themselves some very inexpensive production and a clear signal that the age of conformace control had begun

What is Conformance Control?

In the context of a reservoir produced with some kind of external fluid drive, conformance describes the extent to which the drive uniformly sweeps the hydrocarbon toward the producing wells. A perfectly conforming drive provides a uniform sweep across the entire reservoir; an imperfectly conforming drive leaves unswept pockets of hydrocarbon. Conformance control describes any technique that brings the drive closer to the perfectly conforming condition- in other words, any technique that somehow encourages the drive mechanism to mobilize rather than avoid those hard-to-move pockets of unswept oil and gas.

In the pantheon of techniques to improve oil recovery, conformance control is relatively unambitious, its goal being simply to improve macroscopic sweep efficiency. Most enhanced oil recovery (EOR) techniques, for example, also strive to improve microscopic displacement efficiency using a variety of surfactants and other chemicals to prize away hydrocarbon stuck to the rock surface. Conformance control is also less expensive than most EOR techniques because the treatments are better targeted and logistically far smaller.

Another factor also favors conformance control. By redistributing a waterdrive so it sweeps the reservoir evenly, water cut is often dramatically reduced. For many mature reservoirs, treatment and disposal of produced water dominate production costs, so less water is good. Environmental regulations also push oil companies to reduce water production. In the North Sea, residual oil in produced water dumped into the ocean is restricted to 40 ppm, an upper limit increasingly under pressure from the european community. 

Conformance control during waterflooding covers any technique designed to reduce water production and redistribute waterdrive, either near the wellbore or deep in the reservoir. Near the wellbore, these techniques include unsophisticated expedients such as setting a bridge plug to isolate part of a well, dumping sand or cement in a well to shut off the bottom perforations, and cement squeezing to correct channeling and fill near-well fractures. Deep in the reservoir, water diversion needs chemical treatment.

Initially, straight injection of polymer was tried but proved uneconomical because of the large volumes required to alter reservoir behavior and because polymers tend to get washed out. The current trend is gels, which if correctly placed can do the job more efficiently with much smaller volumes. In the future, potentially less expensive foams including foamed gel may be tried. Ultimately, reducing water production may require a new well. The choice of technique or combination techniques depends crucially on the reservoir and its production history.

Take, for example , the caase of two producing zones separated by an impermeable shale, in which the bottom zone has watered out. The first solution is to cement in the bottom zone. Suppose, though, that the shale barrier does not extend to the producing well. Then success with the cement plug becomes short-lived and water soon starts coning toward the top interval.  The only recourse now is to inject a permeability blocker- some kind of gelling system- deep into the lower zone. The trick is not letting the gelling system invade the upper zone. This can be achieved by pumping through coiled tubing to the top of watered-out zone while simultaneously pumping an inert fluid, water or diesel fuel through the annulus into the upper zone to prevent upward migration of the gelling system. 

Deep gelling systems are also the answer for a high-permeability but watered-out formation sandwiched between two lower permeability formations.  A casing patch or cement squeeze may halt water production momentarily, but long-term shutoff requires a deeper block. The fractured reservoir is a variant of this scenario. If natural fractures are interconected, they can provide a ready conduit for water breakthrough, leaving oil in the matrix trapped and unproducible. The solution is to inject and fill the fractures with a gelling system, that once gelled, forces injection water into the matrix to drive the oil out. 

 BP Exploration and ARCO are currently testing a system comprising PHPA and an aluminum-based cross-linker that is hoped will reach deep in the matrix reservoir of the Kuparuk field in Northern Alaska. The cross-linker is another metal-carboxylate complex, aluminum citrate. But unlike chromium acetate, this links the PHPA in two distinct temperature-controlled stages.In the first stages which occurs rapidly in cold water, each aluminum citrate molecule bonds to just one polymer carboxylate site. In the second stage, which occurs only above 50 degree celcius, the aluminum citrate complex can attach to a second carboxylate group thereby cross-linking two polymer molecules and contributing to produce a gel network. Because the cross-link itself contains carboxylate groups and these have an affinity for water molecules, the formed gel may flow in a beaker, yet provide an adequate permeability block in porous rock.

BP and ARCO's strategy is to pump the system into the reservoir through injection wells, where the cooler temperature of the injection water will promote only the first stage reaction, resulting in a pumpable fluid of low viscosity. Then, as the fluid permeates deep into high-permeability sections of the reservoir and experiences higher temperatures, the second-stage will kick in and enough of a gel will form to divert water-drive to less permeable zones.

  An alternative gelling system that guarantees injectability into matrix rock uses simple inorganic chemicals that have flowing properties nearly identical to those of water. Inorganic gels were discovered in the 1920s and are used to this day for plugging lost circulation, zone squeezing and consolidating weak formations. Their failing for conformance control has been a very rapid gelation time, but recent innovations using aluminum rather than silicon have resolved this problem.

 Besides their inherent ability to deeply permeate matrix rock, inorganic gels have another advantage over their polymer-based cousins. If the treatment fluid gets incorrectly placed causing a deterioration in reservoir performance, inorganic gel can be removed with acid. Of course, the acid has to be able to reach the gel to be able to remove it. Polymer gels, on the other hand, cannot be dismantled easily and are therefore usually in place for the duration. 

 If deep penetration in matrix is one key factor in the conformance control debate, another concern is contamination of the gelling system through contact with ions in the formation water. As noted, the DGS system may be adversely affected by divalent anions. PHPA, on the other hand, both before and after gelling may be affected by divalent cations such as Ca2+, which are relatively ubiquitous in formation waters. 

Tuesday, May 15, 2018

Renew an Old Field with a Horizontal Well

Maraven, S.A., one Venezuela's three national oil companies, is going for the hard-to-get roe in Block 1 of lake Maraicabo, Venezuela. Forty years of production there has left isolated pockets of hydrocarbon, known as attic oil, in the tops of structural and stratigraphic traps. Recovering this attic oil with vertical wells is not usually cost-effective because the thin layer of oil in place increases the likelihood of water coning. 

 Taking a new approach, an integrated team of geoscientists from Maraven and Schlumberger planned, drilled and completed VLA-1035 - Lake Maracaibo's first successful horizontal well- gaining an eight-fold increase in oil production over vertical wells in the same reservoir.

 The motivation for VLA-1035 was provided when Maraven's parent company Petroleos de Venezuela, S.A. (PDVSA) launched a development program for Lake Maracaibo. The plan called for generating 11 billion barrels of additional oil reserves through new wells, horizontal development and reworking of older wells. Although horizontal drilling had been considered in Lake Maracaibo since 1986, attempts by other companies to drill horizontal wells were unsuccessful because of the complex geology or completion problems.

Yet, horizontal drilling seemed the only way to produce from Block 1. A vertical well typically produced 150 barrels of oil per day (BOPD). Most older wells had been shut in as uneconomic, and the wells that were on line typically produced no more than 150 barrels of oil. Some recent wells began producing water immeadiately, others made water within two months. Early breakthrough of water was inevitable because of the reduced vertical heigh of pay, reduced reservoir pressure and increased relative permeability of water to oil.

The Planning Stage

In early 1992, Maraven began assessing the economic and tehnical feasibility of drilling a horizontal drainhole to recover remaining reserves.  Reservoir engineers evaluated production histories to identify regions with recoverable oil and later modeled drainhole performance. Geophysicist used three-dimensional (3D) seismic data, having vertical resolution of tens to hundreds of feet, to obtain a big picture of the reservoir and identify prospective sands. Geologist and sedimentologist examined cores and logs, with vertical resolutions on the order of inches to one foot, to identify sands and model their orientation, continuity and distribution. Petrophysicst working with sedimentologist integrated log and core data with drilling records, including bit and mud data, for 33 wells in the area. This provided an understanding of the mechanical stability of the formation, fluid distribution, oil-water contact location, and flagged possible drilling difficulties.

They targeted reservoir VLA-8 in Block 1, bound on the west by the Icotea fault. It contains a region of low dips (2 degree to 10 degree) called El Pilar and a region of high dips (30 degree to 45 degree) called the Attic. Since 1954, VLA-8 has produced 42 million barrels of the estimated 118 million barrels of oil in place. This production reduced reservoir pressure from 3200 psi to 1800 psi at 6700 ft [2040m] in some areas and raised the oil-water contact. 

Water coning has been a problem from the beginning, with the average water cut in the field increasing from 20% in 1960 to 85% by 1991. The influx of water moves hydrocarbons toward the top of traps, creating isolated pockets of oil. Because of the extensive production in the field, normally desirable high permeabiltiy zones had water, whereas low-permeability zones contained oil.

The attic is considered the last opportunity  for development in Block 1. Three-dimensional seismic data, shot in 1990 and covering 235 square km, revealed the structural complexity of the fold and fault systems that bound the reservoir, and also stratigraphic features within the pay sands. The steeply dipping flanks are difficult to image seismically because a mud layer at the bottom of Lake Maracaibo absorbs high-frequency seismic energies.

 Well-tie sections, time slices and 3D cube displays from Schlumberger's Charisma workstation contributed to understanding the structure. Productive sands in the attic are in the C-6 and C-7 horizons, which have each been divided into three intervals-upper, middle and lower. In addition, seismic attribute sections were generated on the workstation and interpreted. Seismic attributes, such as signal phase and polarity, can reveal subtle characteristics of a seismic trace. In this case, instantaneous phase sections were particularly helpful in confirming the continuity of the C-7 structure. But the steep dip of the beds prevented determining an exact location of the C-7 reservoir.

Maraven was especially interested in the massive C-7 sands, 60 to 200 ft thick, products of deltaic and fluvial depositional environments. Target sands appeared to be the C-7 upper and lower interevals, with the initial preference by Maraven for the lower one.

Their next step was putting the seismic, log and core data into a reservoir model that would help identify the drainhole's position in the sand for maximum production. Modeling performace of the proposed horizontal drainhole in the C-7 sands was accomplished with a black-oil reservoir simulator.

 Based on log and core analysis, the model comprised a partially anisotropic reservoir with a horizontal permeability 250 md and a vertical to horizontal permeability ratio, Kv/Kh, of 0.5. In the model , the reservoir was bounded on one side by an aquifer and on the other by the Icotea fault. Assuming that no more vertical wells would be shut in and that water cut would stabilize, Maraven calculated that existing conventional wells would recover only 18% of the remaining reserves.

To find the most productive drainhole location, Maraven modeled performance for four horizontal drainholes, with lengths of 584 ft , 884 ft, 1200 ft and 1600 ft, in the upper, middle and lower sands. The 1200-ft drain-hole in the C-7 lower sands performed best. Overall, reservoir modeling showed that a horizontal well would recover 40% to 160% more oil than a vertical well. 

After analyzing the seismic interpretation and the reservoir simulation, Maraven geoscientist concluded that a horizontal drainhole could not be drilled without additional information from a pilot well. First, they needed to pinpoint the top and thickness of C-7 with respect to the Icotea fault. Second, they needed to better define the oil-water contact. At this point, they negotiated with Schlumberger to manage drilling the pilot well and the subsequent drainhole under Maraven supervision. As Maraven and Schlumberger geoscientist worked together on the project, specialist from both companies refined the initial geologic and reservoir engineering studies.

Coordinating the project was Anadrill's Bill Lesso, who had worked with Schlumberger's Horizontal Integration Team (HIT), which pioneered an integrated-services approach to drilling horizontal wells. The HIT group found that a coordinator was essential to facilitate communication betwen disciplines and act as a catalyst for decision making. 

The program for drilling and completing the horizontal well took about 10 weeks. Each task in the program was listed chronologically with its projected duration and status. This helped identify both progress and problem areas. Once drilling began, these weekly meetings gave way to daily sessions at a "mission control" center in Lagunillas, 20 miles from the offshore rig but linked to it by phone, fax and data transmission lines. Every morning at 9:00, the team met to discuss drilling or completion operations- whatever was planned for the next 48 hours. The team needed to achieve a consensus on drilling decisions and be on call round the clock during critical operations. To keep team members and interested parties informed, the project coordinator prepared and distributed weekly updates - one page summaries that highlighted progress and issues to be resolved.

Prompt and frequent communication was critical for weaving togehter the expertise of Maraven and Schlumberger specialist. 

Drilling the Pilot Hole

The plan called for an 8 1/2- inch pilot hole deviated 55 degree , with three possible drainhole trajectories to follow.  Log data from the pilot well would be used to pick the best drainhole location. In addition to determining the drainhole trajectory, drilling the pilot hole gave the team an opportunity to learn how directional drilling equipment behaved in the VLA-8 formation.

The well was drilled vertically to a kickoff at 5350 ft [1630 m] , then with a build of 6 degree/100 ft to 50 degree deviation using a steerable bottomhole assembly (BHA). CDR compensated Dual Resistivity and CDN compensated Density Neutron measurements were added to correlate in real time with log data from nearby wells. LWD logs were later complemented by a suite of wireline measurements comprising a resistivity log, two porosity logs, a gamma ray log and the DSI Dipole Shear Sonic Imager log. Tool sticking in the build section of the pilot well, attributed to overbalance caused by low reservoir pressure, precluded logging with a dipmeter tool. The lack of dip information near the well created a formidable challenge when it came time to drill the horizontal drainhole.

Log data from the pilot well were fed into the ELAN Elemental Log Analysis progam, which fits openhole log measurements to a formation model comprised of mineral and pore fluid combinations. The ELAN results showed that the C-7 upper sand,  with higher clay content than the other sands, had lowest effective porosity, but the highest hydrocarbon saturations. Logs of the shaly C-7 upper sand indicated oil in the top 40 ft, with a water leg in the clead sand section below. Consequently, the team directed their attention to the C-7 upper rather than lower sand. 

Next, petrophysicst used the impact Integrated Mechanical Properties Analysis Computation Technique program to evaluate whether the C-7 upper sand could support a horizontal drainhole. The Impact program processes a variety of data - including bulk volume analysis from the ELAN output, vertical and horizontal stresses derived from logs and core measurements, and density logs - to calculate the stress field at the borehole wall for a given well inclination and direction. 

More importantly, it establishes safe mud weights along the trajectory in the borehole. The mud-weight range indicates the degree of difficulty and expense associated with drilling a horizontal well.

Vertical stress was derived from log measurements of the cumulative density of overlying sediments. Horizontal stresses were obtained using diferential strain-curve analysis. In this technique, strain gauges are attached to a core sample, which is then encased in a silicone plug and compressed hydrostatically. Hydrostatic compression closes microcracks that developed when the core was removed. Measuring strain while these cracks close gives the ratio of the horizontal stresses.

Analysis of DSI data gave the compressional and shear velocities needed, along with the bulk density, to compute the dynamic elastic moduli. These computations matched the elastic moduli measured on cores prior to strain curve analysis. The Impact analysis showed the zone to be competent and drillable at high angles. 

In finalizing the horizontal trajectory, the team correlated pilot log data with offset data from two nearby wells, which showed that the C-7 upper dipped up about 5 degree from the pilot well, then flattened out and eventually started dipping down. A 6 degree/ 100 feet build to 95 degree was planned to intersect the target sand at 6380 ft true vertical depth (TVD). Markers that could be identified with the LWD gamma ray or resistivity sensors were chosen to verfiy the approach to horizontal.

Drilling the Horizontal Drainhole

The drainhole was geosteered with an LWD system, providing real-time gamma ray and resistivity logs. Density and neutron porosity data were recorded in downhole memory and used to locate gas, which, if detected, would affect completion strategies. A sedimentologist at the rig analyzed drill cuttings to monitor the location of the drainhole in the target.

The pilot hole was plugged and opened up to allow setting 9 5/8 in. casing at 6062 ft. When drilling began, the close interaction between Maraven and Schlumberger geoscientists was important in allowing the team to respond swiftly to new developments. 

The pilot-hole logs were used to construct a dipping, "layer-cake" resistivity model that could simulate the LWD resistivity response in a drainhole for any depth and deviation. These simulated tool responses would guide the LWD interpreter in advising the driller once real-time LWD logs were available. When simulated and measured resistivities differ, the model is modified by adjusting the dip of the bed with respect to the borehole angle or the depth of the structure. This process is repeated until the simulated and measured resistivity measurements match, indicating the correct model for the depth and dip of the structure.

As the horizontal section began, early correlations between the simulated and real-time LWD measurements indicated a steeper dip than expected. To compensate, the team increased build angle from 6 degree/ 100 ft up to 16 degree / 100 ft. Even so, the drainhole exited the oil section at 6748 ft, striking water. 

  The driller jacked up the inclination to 100 degree to steer the wellbore up toward the oil bottom. Once it was found, the hole was plugged back. LWD logs from this drainhole provided the team with dip information crucial for revising the formation model. The team accounted for the effects of azimuthal changes and high transverse dips relative to the well path, caused by the beds dipping up about 35 degree toward the fault. Any change in azimuth to the left would cause the drainhole to lose elevation in the oil section. A turn to the right would cause a gain in elevation.

 The revised strategy was to land the drainhole in the upper section of the target. Once there, a 95 degree inclination would follow the dip until the CDR curve indicated the well path exiting into overlying shale. The azimuth would be closely controlled.

The new drainhole entered the top of the sand at 6750 ft [2057 m] with an inclination of 87.6 degree. Logs across the target sand from the pilot were then used to navigate the drainhole, with gamma ray and resisitivity measurements from the LWD tool as indicators. The top of the C-7 upper interval contains a series of thin sands and shales each with an identifiable gamma ray signature  . Alternating changes in sand and shaliness as found from the pilot were assigned letters from "a" to "k" -"a,c,e, " indicated sands , "b,d,f..." indicated shales. As the wellbore progressed, correlations indicated that the drainhole had penetrated sandy "a" through shaly "f". Then the team decided to steer up to avoid hitting water. This correlation of sedimentological facies between pilot and drainhole proved to be a powerful geosteering technique. The drainhole reached its planned displacement with 1112 ft [339 m] of net pay sand.

Completion and Production

Several factors influenced the completion of VLA-1035. The overall strategy was to produce through slotted liner, but this hinged on the ability to slide the slotted section to the total depth (TD). An openhole gas section below the 9 5/8 in. shoe found with the CDN log needed to be hydraulically sealed from oil production. In addition, low reservoir pressure of 1200 psi required artificial lift for production.

Consequently, 7-in. casing with the lower section slotted for production, rather than liner, was set to surface. This would provide the pushing power to reach total depth and guarantee gas isolation. CemCADE cementing design and evaluation software analysis was used to determine pump rates, fluid volumes, surface pressures and centralizer calculations for cementing. The 7-in. casing was run to the bottom of the hole, and an inflatable external casing packer was placed above the slotted section to isolate the gas. A port collar placed at the top of horizontal slotted section directed the cement first into the packer and then up the annulus between the 7-in. casing and the openhole and 9 5/8 in. casing. After the packer was inflated, cement was pumped 1500 ft above the 9 5/8 in. shoe to provide the hydraulic seal. Finally, 3 1/2 in. tubing equipped with two gas lift mandrels was run.

During the first two weeks of production, chokes ranging from 3/8 in. to 1 in. were tested, with the largest diameter yielding 2456 BOPD. With a 5/8 in. choke, the well averaged 1400 BOPD and a 4% water cut in the first five months and continues to produce 1000 BOPD with a 12% water cut today.

Maraven has since drilled two additional horizontal wells with Anadrill in Lake Maracaibo, including a reentry well, and is studying the optimal length of a horizontal drainhole. In 1994, Maraven plans to drill 11 horizontal wells, building to 36 in 1999. By the year 2000, horizontal wells are predicted to account for 20% of oil production in Venezuela. 



Sunday, May 13, 2018

The State of the Water Base Mud Art

This article will now concentrate on advances in water base mud (WBM) technology by looking at two distinct directions of development: the use of polyols for shale inhibition and the introduction of mixed-metal hydroxides to improve hole cleaning and help reduce formation damage.

Polyol muds-Polyol is the generic name for a wide class of chemicals-including glycerol, polyglicerol or gylcols such as proplylene glycol-that are usually used in conjunction with an encapsulating polymer (PHPA) and inhibitive brine phase (KCl). These materials are nontoxic and pass the environmental protocols, including those laid down in Norway, the UK, The Netherlands, Denmark and the USA.

 Glycols in mud were proposed as lubricants and shale inhibitors as early as the 1960s. But it was not until the late 1980s that the materials became widely considered. Properly engineered polyol muds are robust, highly inhibitive and often cost-effective. Compared with other WBM systems, low volumes are typically required. Polyols have a number of different effects, such as lubricating the drillstring, opoosing bit balling (where clays adhere to the bit) and improving fluid loss. Today, it is their shale-inhibiting properties that attract most attention. For example, test carried out by BP show that the addition of 3 to 5% by volume of polyglycol to a KCl-PHPA mud dramatically improves shale stabilization. 

Field experience using polyol muds has shown improved wellbore stability and yielded cuttings that are harder and drier than those usually associated with WBM.  

Mixed-metal hydroxide (MMH) mud - MMH mud has a low environmental impact and has been used extensively around the world in many situations: horizontal and short-radius wells, unconsolidated or depleted sandstone, high-temperature, unstable shales, and wells with severe lost circulation. Its principal benefit is excellent hole-cleaning properties.

Many new mud systems-including polyol muds -are extensions of existing fluids, with perhaps a few improved chemicals  added. However, MMH mud is a complete departure from existing technology. It is based on an insoluble inorganic, cyrstalline compound containing two or more metals in a hydroxide lattice-usually mixed alumunium/magnesium hydroxide, which is oxygen-deficient. When added to prehydrated bentonite, the positively charged MM particles interact with the negatively charged clays forming a strong complex that behaves like an elastic solid when at rest. 

This gives the fluid its unusual rheology: an exceptionally low plastic viscosity-yield point ratio. Conventional muds with high gel strength usually require high energy to initiate circulation, generating pressure surges in the annulus once flow has been established. Although MM has great gel strength at rest , the structure is easily broken. So it can be transformed into a low-viscosity fluid that does not induce significant friction losses during circulation and gives good hole cleaning at low pump rates even in high-angle wells. 

Selecting a reliable chemical formulation for the drilling fluid so that it exhibits the required properties is one part of the job. Maintaining these properties during drilling is another. 

Circulation of drilling fluid may be considered a chemical process with the wellbore acting as a reactor vessel. In this reactor, the composition of the drilling fluid will be changed dynamically by such factors as filtration at the wellbore and evaporation at the surface; solids will be added and taken away by the drilling process and the solids-control equipment; chemicals will be lost as they adhere to the borehole wall and to cuttings, aand they will be added routinely at the surface, formation fluids will contaminate the mud, perhaps causing flocculation or loss of viscosity and oxygen may become entrained.

Under these circumstances effective management is not trivial. Nevertheless, basic process control techniques have been applied rigside for some years to aid in the selection and maintenance of the fluid formulation and to optimize the solids-control equipment - such as shale shakers and centrifuges. This approach is often linked to incentive contracts, where savings in mud costs are shared between contractor and operator, and has led to remarkable savings in mud cost.

For example, with a systems approach to drilling fluid management for 16 wells offshore Dubai, mud costs were cut in half and reduced as a proportion of total drilling costs from 6% to 3%. At the same time, hole condition remained the same or better - this was assessed by looking at hole diameter, time to run casing and mud usage per foot of well drilled. 

Such an approach is based on three premises:
  • More frequent and more precise measurements, for example five mud checks per day and the introduction of advanced measurement techniques.
  • Efficient data management using mass balance techniques - which track the volumes of chemicals, hole and cuttings- and computerized data storage and acquisition.
  • Integration of the management of the solids control equipment with that of the drilling fluids.

Solid-control efficiency-the percentage of drilled solids removed versus the total amount drilled- is central to drilling efficiency and is a function of the surface equipment, drilling parameters and mud properties. For example, muds that have a lower tendency to hydrate or disperse drilled cuttings generally give higher solids-control efficiency.  

The significance of solids control is that penetration rate is closely linked to the volume of solids in the fluid. The greater the amount of solids, the slower the rate of drilling.  Mud solids are divided into two categories: high-gravity solids (HGS) comprising the weighting agent, usually barite; and low-gravity solids (LGS) made up from clays, polymers and bridging materials deliberately put in the mud, plus drilled solids from dispersed cuttings and ground rock.

The volume of HGS should be maximized, so that the total volume of solids in the mud is minimized, while still achieving the density required to control formation pressures. Therefore, drilled solids must be removed by the solids-control equipment. Howeer, some solids become dispersed as fine particles that cannot be removedd effectively. In this case, the fluid must be diluted with fresh mud containing no drilled solids.

But desirable properties are not always optimum ones. For instance, zero drilled solids at the bit is desirable. However, achieving zero drilled solids would increase mud costs dramatically. It is the job of mud management to plot the optimum course. To do this successfully requires accurate and regular input data.

Traditional field practice is to measure mud density and viscosity ( using a Marsh funnel) about every 30 minutes at both the return line and the suction pit. Other properties- such as rheology, mud solids, fluid loss, oil/water ratio (for OBM), pH, cation exchange capacity, and titrations for chloride and calcium- are measured once every 8 or 12 hours ( depending on drilling conditions) using 1-liter samples taken from the flowline or the active pit. These determinations are then used as a basis for mud treatment until the next set of measurement is made.

To gain better control over the mud system, a more meaningful monitoring strategy may be required. Simply increasing the frequency of traditional measuring techniques to at least five times a day and making sampling more representative of the whole mud system has improved control and significantly reduced the amount of chemicals used to drill a well.  

Mud solids monitor- A common indicator describing the solids content in the mud is the LGS-HGS volume ratio. This is traditionally measured using the retort,a technique that requires good operator skills, takes at least 45 minutes and often has an error margin of more than 15%.


Friday, May 4, 2018

Designing and Managing Drilling Fluid (2)

Shale instability is largely driven by changes in stress and chemical alteration caused by the infiltration of mud filtrate containing water. Over the years, ways have been sought to limit interaction between mud filtrate and water-sensitive formations. So, for example, in the late 1960s, studies of mud-shale reactions resulted in the introduction of a water-base mud (WBM) that combines potassium chloride (KCl) with a polymer called partially-hydrolyzed polyacrylamide-KCl-PHPA mud. PHPA helps stabilize shale by coating it with a protective layer of polymer-the role of KCl will be discussed later.

The introduction of KCl-PHPA mud reduced the frequency and severity of shale instability problems so that deviated wells in highly water-reactive formations could be drilled, although often still at a high cost and with considerable difficulty. Since then, there have been numerous variations on this theme as well as other types of WBM aimed at inhibiting shale. 

However, in the 1970s, the industry turned increasingly towards oil-base mud (OBM) as a means of controlling reactive shale.  Today, OBM not only provides excellent wellbore stability but also good lubrication, temperature stability, a reduced risk of diffrential sticking and low formation damage potential. OBM has been invaluable in the economic development of many oil and gas reserves.

 The use of OBM would probably have continued to expand through the late 1980s and into the 1990s but for the realization that, even with low-toxicity mineral base-oil, the disposal of OBM cuttings can have a lasting environmental impact. In many areas this awareness led to legislation prohibiting or limiting the discharge of these wastes.

To develop alternative nontoxic muds that match the performance of OBM requires an understanding of the reactions that occur between complex, often poorly characterized mud systems and equally complex, highly variable shale formations.

Requisites for a Successful Drilling Fluid

Most OBM is an invert emulsion comprising droplets of aqueous fluid surrounded by oil, which forms the continuous phase. A layer of surfactant on the surface of the water droplet acts like a semipermeable membrane, separating the aqueous solution in the mud from the formation and its water. Water will pass through this membrane from the solution with the lowest concentration of a salt to one with the highest-osmosis.

A key method of maintaining shale stability using OBM is to ensure that the ionic concentration of the salts in the aqueous-internal-phase of the mud is sufficiently high, so that the chemical potential of the water in the mud is equal or lower than that of the formation water in the shale. When both solutions have the same chemical potential, water will not move, leaving the shale unchanged. If the water in the internal phase of the mud has a lower chemical potential than the fluid in the formation, water will travel from the shale to the mud, drying out the rock. Unless dehydration is excessive, this drying out usually leaves the wellbore in good condition.

In WBM, there have been many efforts to protect a water-sensitive formation from mud filtrate. One technique is to introduce a buffer in the form of blocking and plastering agents, ranging from starches and celluloses, through polyacrylamides to asphalts and gilsonites. Total control cannot be achieved in this way so specific inhibiting cations- chiefly potassium and calcium ions -are traditionally added to the base water to inhibit the clay from dispersing-to stop it from breaking up when attacked by aqueous solution. This is achieved by providing cation exchange with the clays in the shale the K+ or Ca2+ commonly replace the sodium ion (Na+) associated with the clay in the shale, creating a more stable rock that is better able to resist hydration. Hence KCl-PHPA fluids.

The movement of WBM filtrate from the wellbore into the surrounding shale is controlled by the difference between the chemical potentials of the various species in the mud, and the corresponding chemical potentials within the formation. Chemical potential depends both on the mud's hydrostatic pressure in the wellbore and on its chemical composition.

To design an effective WBM, it is necessary to know the relative importance of mud differential pressure versus chemical concentration and composition, and how this relates to the type of mud and formation. For example, if the rock is chemically inert to WBM filtrate (as is the case with sandstone) then invasion is controlled solely by the differences between the wellbore pressure and the pore pressure within the rock. But for shale, opinion varies. Some experimenters suggest that the shale itself can act as a semipermeable membrane, making the chemical components the key determinant.

A number of relatively new types of mud systems have been introduced. For example, one route is to substitue the oil phase in OBM with synthetic chemicals. In this way, the excellent characteristics of OBM may be reproduced with a more rapidly biodegraded continous phase than was available before. 

 Typical synthetic base chemicals include esters, ethers, polyalphaolefins, linear olefins and linear akly benzenes. One of the chief disadvantages of these systems is that they tend to be relatively expensive compared to conventional OBM. However, such systems can still be cost-effective options compared to WBM. 


Wednesday, May 2, 2018

Designing and Managing Drilling Fluid

Gone are the days when drilling fluid - or mud as it is commonly called - comprised only clay and water. Today, the drilling engineer designing a mud program chooses from a comprehensive catalog of ingredients. The aim is to select an environmentally acceptable fluid that suits the well and the formation being drilled, to understand the mud's limitations, and then to manage operations efficiently within thoose limitations.

There are good reasons to improve drilling fluid performance and management, not least of which is economics. Mud may represents 5% to 15% of drilling costs but may cause 100% of drilling problems. Drilling fluids play sophisticated roles in the drilling process: stabilizing the wellbore without damaging the formation, keeping formation fluids at bay, clearing cuttings from the bit face, and lubricating the bit and drillstring, to name a few. High-angle wells, high temperatures and log, horizontal sections through pay zones make even more rigorous demands on drilling fluids.

Furthermore, increasing enviromental concerns have limited the use of some of the most effective drilling fluids and additives. At the same time, as part of the industry's drive for improved cost-effectiveness, drilling fluid performance has come under ever closer scrutiny.

This article looks at the factors influencing fluid choice, detailing two new types of mud. Then it will discuss fluid management during drilling.

What influences the choice of fluid?

Among the many factors to consider when choosing a drilling fluid are the well's design, anticipated formation pressures and rock mechanics, formation chemistry, the need to limit damage to the producing formation, temperature, environmental regulations, logistics, and economics.

To meet these design factors, drilling fluids offer a complex array of interrelated properties. Five basic properties are usually defined by the well program and monitored during drilling: rheology, density, fluid loss, solids content and chemical properties.

For any type of drilling fluid, all five properties may, to some extent, be manipulated using additives. However, the resulting chemical properties of a fluid depend largerly on the type of mud chosen. And this choice rests on the type of well, the nature of the formations to be drilled and the environmental circumstances of the well.

Issue & Decision

  • Specific healt and environmental concerns on type of mud and disposal of cuttings -> Determines mud system cuttings treatment/disposal strategy.
  • Remote location well -> May prevent the use of systems that consume large quantities of chemicals.
  • Composition and arrangement of the minerals in the formation and the clay chemistry -> Determines mud chemistry/ composition.
  •  Well profile/ angle -> Indicates the rheology needed to optimize hole cleaning. High-angle wells may need enhanced lubricity.
  • Strength and stress states versus hole angles -> Potential wellbore stability issues may concern mud weight. 
  •  Length of exposed open hole -> Greater inhibition needed for longer sections.
  •  Pore pressure -> Determines minimum mud weight needed to prevent blowout.
  • Rock strength-fracture gradient -> Indicates maximum mud weight that will not fracture well.
  • High -temperature well -> More than 275-300 degree F may cause product degradation.
  • Formation being drilled is pay zone -> Requires nondamaging mud to limit invasion, wettability effects of mud, potential emulsion blockage of the formation, fines mobilization and invasion, scale formation.

 Shales are the most common rock types encountered while drilling for oil and gas and give rise to more problems per meter drilled than any other type of formation. Estimates of worldwide, nonproductive cost associated with shale problems are put at $500 to $600 million anually. Common drilling problems like stuck pipe arise from hole closure and collapse, erosion and poor mud condition. In addition, the inferior wellbore quality often encountered in shales may make logging and completion operations difficult or impossible.