Tuesday, November 28, 2017

Matrix Acidizing - Diverting with Foam case study

Foam, a stable mixture of liquid and gas, has been used as a diverter in sandstone acidizing since 1969. By the usual criteria, it is almost perfect. It is cheap to produce; it does a decent job diverting; it does not interact adversely with the formation and formation fluids; and it cleans up rapidly. Foam is produced by injecting nitrogen into soapy water- typically, nitrogen occupies 55 to 75% of foam volume. The soapy water is a mixture of water and small amount of surfactant, or foamer. Injected downhole, foam penetrates the pore space where the cumulative viscous effect of the bubbles blocks further entry of the treating fluid.

 Foam's only drawback is that with time the bubbles break and diversion ceases. This can be seen in laboratory experiments, in which foam is injected simultaneously through two long sand packs, one with high permeability mimicking a thief zone, the other with low permeability mimicking a damaged zone. The cores are preflushed and then injected with foam. Then, acid is injected. At first, diversion works fine, with the low-permeabilty sand pack taking an increasingly greater proportion of the acid. But after about one hour, the foam has broken and the thief zone starts monopolizing the treatment fluid.

Researcher at the Dowell Schlumberger engineering center at Saint-Etienne, France discovered that this breakdown can be postponed by saturating the formation with a preflush of surfactant before injecting the foam and also injecting surfactant with every subsequent stage in the acid process. The surfactant adheres to the rock surface and minimizes adpsorption of surfactant contained in foam, preserving the foam. 

As before, the foam progressively diverts treatment fluid to the damaged zone, but now the diversion holds for at least 100 minutes. If necessary, damaged formation can first be cleaned with mutual solvent to remove oil in the near wellbore region - oil destroys foam - and to ensure the rock surface is water wet and receptive to the surfactant. 

Yet further improvement to foam diversion can be achieved by halting injection for about 10 minutes after foam injection. The diversion of treatment fluid to the damaged sand pack now takes effect almost immediately, rather than almost 50 minutes. It seems that given a 10-minute quiescent period, foam in low-permeabiity sand prematurely breaks down - scientist are not sure why. The combination of surfactant injection and 10-minute shut-in comprises the new FoamMAT diversion service that has been successfull application in the Gulf of Mexico and Africa.


Monday, November 27, 2017

Matrix Acidizing chapter 3

A challenge that must be faced in either lithology is diversion. As acid is pumped, it flows preferentially along the most permeable path into the formation. The acid opens these paths up even more, and less permeable, damaged zones are almost guaranteed not to receive adequate treatment. Some technique to divert the treatment fluid toward more damaged formation or damaged perforations is therefore mandatory.

There is a variety of diversion techniques. Treatment fluid can be directed exclusively toward a low-permeability zone using drillpipe or coiled-tubing conveyed tools equipped with mechanical packers. Alternatively, flow can be blocked at individual perforations taking most of the treatment fluid by injecting ball sealers that seat on the perforations. In carbonates, bridging agents such as benzoic acid particles or salt can be used to create a filter cake inside wormholes, encouraging the acid to go elsewhere. In sandstones, microscopic agents such as oil-soluble resins can create a filter cake on the sand face. Chemical diverters such as viscous gels and foams created with nitrogen are used to block high-permeability pathways within the matrix.  


If the principle of matrix acidizing appears straightforward, the practice is a mine field of complex decisions.  Service companies offer a vast selection of acid systems and diverters, and few people would design the same job the same way. In addition, matrix acid jobs are low budget, typically between $5000 and $10,000 an operation, so the careful attention given to planning much more expensive acid fracturing treatments is often missing. Matrix acidizing is traditionally carried out using local rules of thumb. Worse, jobs are poorly evaluated. 

The question that should always be asked before any other is "Why is the well under producing?" And then : " Will production increase with matrix acidizing?" Production may be constricted for a reason other than damage around the borehole. The only way to find out is through pressure analysis from the deep formation through the wellhead, using production history, well tests and analysis of the well's flowing pressures, such as provided by NODAL analysis.

The crud maxim that matrix acidizing will benefit any well with positive skin has several exceptions. Too low a perforation density, multiphase flow, and turbulent gas flow are some factors that cause positive skin in wells that otherwise may be undamaged. 
NODAL analysis, which predicts a well steady-state production pressures, refines this checklist. For example, by comparing tubing-intake curves -essentially the expected pressure drop in the tubing as function of production rate-with the well's inflow-performance curve -expected flow into the well as a function of downhole well pressure -one can readily see if the well completion is restricting flow. Comparing a NODAL analysis with actual measured pressures also helps pinpoint the location of any damage. Damage does not occur only in the formation surrounding the borehole. It can occur just as easily inside tubing, in a gravel-pack or in gravel-pack perforation tunnel.


Thursday, November 23, 2017

Matrix Acidizing chapter 2

By comparison, the reaction between HF and sandstones is much slower. Mud acidizing seeks to unblock existing pathways for production by dissolving wellbore damage and minerals filling the interstitial pore space, rather than by creating new pathways. The HF reacts mainly with the associated minerals of sandstones, rather than the quartz. The acid reactions caused by the associated minerals - clays, feldspars and micas can create precipitants that may cause plugging. Much of the design of a sandstone acid job is aimed at preventing this. 

The usual practice is to preflush the formation with HCl to dissolve associated carbonate minerals. If these were left to react with HF, they would produce calcium fluoride (CaF2) which precipitates easily. Then the HF-HCl mud acid is injected. Finally, the formation is overflushed with weak HCl, hydrocarbon or ammonium chloried (NH4Cl). This pushes reaction products far from the immediate wellbore zone so that if precipitation occurs, production is not too constricted when the well is brought back on line. 

 Another plugging danger is from fine particles, native to the sandstone, dislodged by the acid but not fully dissolved. To minimize this eventuality, Shell in 1974 proposed lower pumping rates - less likely to dislodge fines - and more important, a chemical system that did not contain HF explicity, instead creating it through a chain of reaction within the formation. In principle, this allows greater depth of penetration and longer reaction times for maximum dissolution of fines. 

As HF is spent, dissolving clays and other minerals, it is constantly replenished through hydrolisis from the remaining fluoboric acid. The slow rate of this conversion helps guarantee a retarded action and therefore deeper HF penetration. As a bonus, the fluoboric acid itself reacts with the clays and silt, forming borosilicates that appear to help bind the fines to large grains. Recent treatments with fluoboric acid for Ashland Nigeria have confirmed the power of this technique. 

After in all, sandstone acidizing poses a greater challenge than carbonate acidizing and certainly generates more than its fair share of controversy among both operators and service companies.


Matrix Acidizing chapter 1

The simple aim of matrix acidizing is to improve production - reduce skin in reservoir engineer parlance -by dissolving formation damage or creating new pathways within several inches to a foot or two around the borehole. This is done by pumping treatment fluid at relatively low pressure to avoid fracturing the formation. Compared with high-pressure fracturing, matrix acidizing, is a low-volume, low-budget operation.

Matrix acidizing is almost as old as oil-well drilling itself. A Standard Oil patent for acidizing limestone with hydrochloric acid (HCL) dates from 1896, and the technique was first used a year earlier by the Ohio Oil Company. Reportedly, oil wells increased in production three times, ad gas wells four times. Unfortunately there was a snag - the acid severely corroded the well casing. The technique declined in popularity and lay dormant for about 30 years.

Then 1n 1931 , Dr. John Grebe of the Dow Chemical Company discovered that arsenic inhibited the action of HCl on metal. The following year, the Michigan-based Pure Oil Company requested assistance from Dow Chemical Company to pump 500 gallons of HCl into a limestone producer using arsenic as an inhibitor. The previouslnya dead well produced 16 barrels of oil per day, and interest in acidizing was reborn. Dow formed a subsidiary later called Dowell to handle the new business. Three years later, Halliburton Oil Well Cementing Co. also began providing a commercial acidizing service.

 Sandstone acidizing with hydrofloric acid (HF) - hydrochloric acid does not react with silicate minerals - was patented by Standard Oil company in 1933, but experiments in Texas the same year by an indepedent discover of the technique caused plugging of a permeable formation. Commercial use of HF had to wait until 1940, when Dowell hit on the idea of combining it with HCL to reduce the possibility of reaction products precipitating out of solution and plugging the formation. The mixture, called mud acid, was first applied in the Gulf Coast to remove mudcake damage.



Wednesday, November 22, 2017

High-Permeability Stimulation

A Classic fracture stimulation creates narrow conduits that reach deep into a formation - typically, about 2.5 millimeters wide and up to 1000 ft long. Since the 1940s, relatively low-permeability formations -less than 20 millidarcies (md) - have been successfully fractured to give worthwhile increases in productivity.

However, as formation permeability increases, creating and propagating fractures become more difficult and economically less necesary. In high-permeability reservoirs, formation damage is usually diagnosed as the major restraint on productivity and matrix acidization treatments are prescribed as the solution.

 But matrix acidization cannot solve every problem. The volume of damaged rock sometimes requires uneconomically large quantities of acid. The damage may be beyond the reach of the matrix treatment. Diverting acid into the right parts of the formation may also be difficult. Additionally, the aqueous treatment fluid or the acid itself may threaten the integrity of the wellbore by dissolving cementing material that holds particle of rock together. 

An alternative strategy for stimulating high-permeability wells has therefore emerged : the creation of fractures that are typically less than 100 ft long up to 1 in. (2.5 centimeters) wide after closure. To appreciate how short, wide fracture  stimulate high-permeability formations, one must examine the factors governing postfracture productivity.

The permeability contrast between the formation and the propped fracture is a key determinant of the optimum fracture length. In low-permeability formations there is a large contrast -and therefore a high relative conductivity - and increased fracture length can yield improved productivity.

In high-permeabiltiy formations, relative conductivity is about two orders of magnitude smaller. Increasing the length of conventional fractures offers only minimal improvement in productivity and cannot be justified economically. However, the productive performance of the fracture is detrmined by the dimensionless fracture conductivity which is directly proportional to the fracture width.  Conductivity can be raised by increasing fracture width. 

 In 1984, in Purdhoe Bay, Alaska, USA, Sohio (now BP Exploration) fractured a well with a permeability of about 60 md. The overriding aim of the exercise was to stimulate the well while avoiding fracturing into the oil/water contact (OWC) about 115 ft below the lowermost perforation.

In a relatively small fracturing treatment, some 15,000 gal (57 m3) of gelled fluid were pumped at 45 bbl/min, placing 5440 of proppant in the fracture. This treatment was calculated to be sufficient to create a fracture with a propped length of 43 ft, which based on the assumption that one foot of lateral extension would result in one foot of downward fracture migration, left the fracture easily short of the OWC. The treatment was a mechanical success and production increased by 133%  -versus a theoritacal maximum of 160%. 

After this job, attention shifted to the North Sea. The Valhal field, offshore Norway, has a soft chalk reservoir. Amoco production Co. found that, although the formation was not highly permeable (about 2 md) , it was very unstable and conventional stimulation was difficult. After acid fracturing, the acid-etched channels quickly collapsed as pore pressure was reduced. And after a convetional propped fracture, the proppant became embedded in the soft rock, destroying fracture conductivity.

Experience around the world has enabled development of a methodology for selecting wells for tip-screenout treatments. There are three classes of candidate:
  • Reservoirs with significant wellbore damage, perhaps caused by formation colapse as the pore pressure reduce during depletion. Past matrix treatments have failed, and short, wide fractures are designed to bypass the damage and connect the undamaged part of the reservoir with the wellbore.
  • Reservoirs with fine migration. A short, wide fracture can alleviate this by reducing pressure losses and velocities in the reservoir sand near the wellbore.
  • Multiple pay zones in laminated sand-shale sequences. The thin sand laminae may not communicate efficiently with the wellbore until a fracture provides a continous connection to the perforation.

 Candidate selection is a multidisciplinary task. Basic openhole logs detect sands and their bounding shales, and indicate their relative permeability and degree of invasion - gaining an insight into the formation's natural permeability before damage, the depth of invasion, the presence of zones thinner than 5 ft (1.5 m) and the formation strength. Specialized techniques like microresistivity logging may then be used to detect thinner layers of interbedded sand-shale laminae. Logs also detect water-bearing zones which must be considered during the design. Pressure transient analysis is used to identify wellbore damage and quantify the production potential of the well. After a candidate well has been identified, the next stage is to design the treatment, a process that relies on knowledge of the rock's mechanical properties and an estimate of the stresses in the reservoir and adjacent rock. 

Mechanical properties can be derived using cores, logs, and direct in-situ measurements. In many cases, however, retrieving good cores  and then accurately testing them in the laboratory are difficult. Log-derived mechanical properties rely on density and sonic measurements. Both compressional and shear sonic measurements work well in consolidated, fast formations. But in soft, slow formations, conventional sonic tools cannot measure shear wave velocity. However, a recently introduced dipole sonic tool can now make these shear wave velocity measurements in any formation.

In practice, there is rarely a comprehensive collection of core and log data with which to build a model predicting fracture shape, used for treatment design. To plug this knowledge gap, data are collected using stress test.

Stress tests consist of pumping a relatively small volume of ungelled fluid without proppant into the formation at sufficient pressure to fracture the well. In normal, low-permeability stress test pumping is then stopped and the pressure can be monitored during flowback. However, in high-permeability formations, the fluid normally leaks off into the formation rather than flowing back. Stress test are repeated several times and the resulting pressure measurements are used to dtermine the minimum in-situ stress, whic equals the closure pressure of the fracture.

Analysis of data from stress test and larger-volume calibration test-which fracture the formation usually using gelled fluid without proppant- enables choice of the most suitable fracture geometry model and confirmation of the fluid leakoff coefficient.  

The models assume that rock is an elastic material , meaning that its deformation is reversible. Dowell Schlumberger is currently examining whether this assumption holds for soft formations, as it is an important factor when looking at the fracture closure and the stress it exerts on the proppant pack. If closure stress is less than anticipated, the proppant pack could become unstable during production - unless the treatment has included a gravel pack. 

Calibration tests also provide a more accurate way of measuring fluid-loss characteristics of the fracturing fluid than can be devised in a laboratory. Fluid loss depends on the viscosity and wall-building capability of the fracturing fluid, the viscosity and compressibility of the reservoir fluid, and the permeability and porosity of the formation. In a formation with high porosity and permeability, fluid loss can be controlled by increasing the viscosity of the fracturing fluid or enhancing the fluid's wall-building capability on the fracture face by the addition of polymers and properly sized fluid-loss control agents.  

Once the choice of fracturing fluid is confirmed, the next step is to design a pumping schedule capable of delivering the necessary high proppant concentrations. The data generated by stres and calibration test are fed into the chosen fracture geometry model, which calculates the volume required to initially propagate the fracture to a predetermined length. 

Tuesday, November 21, 2017

Enhanced Fracture Treatment Evaluation

Fracture design may be fine-tuned by careful postjob evaluation. This tells whether the job went as planned, and test the validity of the plan and the variables on which it was based. Postfracture evaluation requires a drawdown and buildup test, which indicates fracture skin and whether the actual fracture length and conductivity match those planned. This testing is not a common procedure because operators are usually hesitant to stop production for the 10 to 14 days required for the buildup. But in some fields, the practice becoming more common in a few, select wells. For example, in BP's Ravenspurn South field in the UK sector of the North Sea, an extensive program of data collection and analysis was performed on the first six development wells. This included extensive pre -and - post frac well testing, logging and recording of bottomhole pressures during job execution. The program helped optimization of job design for the remainder of the field, leading to significant reduction in the number of wells required. 

A typical problem is that postreatment transient pressure analysis shows the fracture is shorter than indicated by the volume and leakoff of pumped fluid. There could be several reasons for the disparity. A common reason, however, is that most postfracture evaluation models assume ideal reservoir conditions - homogeneous and isotropic formations, uniform fracture width and conductivity and absence of skin damage.

Monday, November 20, 2017

Progress in Fracture Treatment Design chapter 2

Pivotal to designing the treatment- and to deciding whether to do one at all -is cost benefit analysis , relating cost of the fracture job to increased well productivity. The more fracture length for a given fracture conductivity, the more productivity, but also the more costly the fracture job. This analysis, called net present value, is done with simulators that find the optimum fracture length and conductivity for a given payback schedule. Too short a fracture, or too low a conductivity, and the increase in well productivity won't cover the cost of fracture treatment ; too long, and the extra fracture length will add significantly to cost but negligibly to production. Some simulators model fracturing economics in longer terms ; they tell , for example, for a well with a given deliverability, amortized at a certain rate, how much should be spent on hydraulic fracturing given a future oil price.

 Fracture Geometry Modeling

The need to understand hydraulic fracturing stimulated advances in basic rock mechanics. A key finding was of Hubbert and Willis, in 1957, showing that fractures in the earth are usually vertical, not horizontal. They reasoned that because a fracture is a plane of parting in rock, the rock will open in the direction of least resistance. At the depth of most pay zones, overburden exerts the greatest stress, so the direction of least stress is therefore horizontal. Fractures open perpendicular to this direction and are therefore vertical. In shallow wells, or where thrusting is active, horizontal stress may exceed vertical stress and horizontal fractures may form.

By the 1960s, fractures created below 1000 or 2000 ft were accepted as vertical. Operators then posed some difficult questions : How high does the fracture grow? How can we prevent it from extending into the gas or water zone? How does fracture height relate to fracture width and lenght? And how do we optimize fracture dimensions?

 A major task of rock mechanics became the prediction of fracture height, length and width for a given injection rate, duration of injection and fluid leakoff. Needed for this prediction is a model of how a fracture propagates in rock.

Today, a number of models occupy a continuum from 2D to pseudo-three dimensional (P3D) and fully 3D. The basic difference between 2D and 3D models is that in 2D models, fracture height is fixed or set equal to length , whereas in 3D models, fracture height, length, and width can all vary somewhat independently. 

The 3D approach is more realistic because fracture height is not determined by lithology but by vertical variation in the magnitude of least principal stresses, which often but always follow lithologic units. The greater the vertical contrast in least principal stresses, the better fracture height is contained.

The perf and the frac : what's the link?

Field wisdom holds that the ideal perforation lies in the plane normal to the minimum far-field stress direction. This perforation links most directly with the induced fracture, minimizing pressure drop near the borehole. Other perforations probably connect with the fracture indirectly, if at all. But because fracture azimuth is generally not known and because alignable perforating guns are not readily available, conventional guns shooting at closely spaced angles around 360 degree are generally used. These are called phased guns. The closer the angle (phasing) between perforations, the better chance of having more perforations in or near the ideal plane. Not until recently, however, were large-scale experiments performed to evaluate the relationship between perforations and hydraulic fractures. 

Behrmann and Elbel of Schlumberger and Dowell Schlumberger , respectively , used full-scale perforators on steel casing cemented into sandstone blocks placed in a  triaxial stess cell. They made several observations about the relationship between perforation orientation and stress direction. They found that fractures initiate from the wellbore wall in the optimum hydraulic fracture direction, from perforations nearest this direction, or both. Fractures tend not to form at other perforations. 

The best perforation-to-fracture communication is achieved when perforations are within 10 degree of the far-field minimum horizontal stress. This means that perforations not optimally oriented may result in a large pressure drop, or proppant bridging, when pad and slurry flow around the annulus to the fracture. As expected , the maximum number of perforations in communication with the fracture is achieved with a perforating gun having the smallest possible angle between shots.