Wednesday, December 6, 2017

Wellbore Damage Chapter 2

The interplay of oil and water in porous rock provides two remaining types of damage occuring only in the formation-wettability change and water block. In their native state, most rocks are water-wet, which is good news for oil production. The water clings to the mineral surfaces leaving the pore space available for hydrocarbon production. Oil-base mud can reverse the situation, rendering the rock surface oil-wet , pushing the water phase into the pores and impeding production. A solution is to inject mutual solvent to remove the oil-wetting phase and then water-wetting surfactants to reestablish the water wet conditions. 

Finally, water block occurs when water-base fluid flushes a hydrocarbon zone so completely that the relative permeability to oil is reduced to zero - this can occur without a wettability change. The solution is again mutual solvents and surfactants, this time to reduce interfacial tension between the fluids, and to give the oil some degree of relative permeability and a chance to move out.


Assessing the nature of the damage is difficult because direct evidence is frequently lacking. The engineer must use all available information : the well history, laboratory test data, and experience gained in previous operations in the reservoir. The initial goal, of course is selecting the treatment fluid. Later, the exact pumping schedule - volumes, rates, number of diverter stages - must be worked out.  

Since carbonate acidizing with HCL circumvents damage, the main challenge of fluid selection lies almost entirely with sandstone acidizing where damage must be removed. Laboratory testing on cores and the oil can positively ensure that a given HF-HFCL mud acid system will perform as desired- it is particularly recommended when working in a new field. These tests first examine the mineralogy of the rock to help pick the treating fluid. Then, compatibility tests, conducted between treating fluid and the oil, make sure that mixing them produces no emulsion or sludge. Finally, an acid response curve is obtained by injecting the treating fluid into a cleaned core plug, under reservoir conditions of temperature and pressure, and monitoring the resulting change in permeability.  The acid response curve indicates how treating fluid affects the rock matrix - the design engineer strives for a healthy permeability increase. 

Most treatment fluid selection ofr sandstone acidizing builds on recommendations established by McLeod in the early 1980s. The choice is between different strenghts of the HCL-HF combination and depends on formation permeability, and clay and silt content. For example, higher strengths are used  for high-permeability rock with low silt and clay content  - high strength acid in low-permeability rock can create precipitations and fines problems. Strenghts are reduced as temperature increases because the rate of reaction then increases.

Whatever their level of sophistication, acidizing models must deal with four processes simultaneously:
  • tracking of fluid stages as they are pumped down the tubing, taking into account differing hydrostatic and friction losses.
  • Movement of luids through the porous formation.
  • Dissolution of damage and/or matrix by acid.
  • Accumulation and effect of diverters.

All four phenomena are interdependent. Diverter placement depends on the injection regime ; the injection regime depends on formation permeability; formation permeability depends on acid dissolution.

 Execution and Evaluation

Sophisticated planning goes only part way to ensuring the success of a matrix acidizing  operation. Just as important is job execution and monitoring. In a study of 650 matrix acidizing jobs conducted worldwide for AGIP, stimulation expert Giovanni Paccaloni estimated that 12% were outright failure, and that 73% of these failures were due to poor field practice. Just 27% of the failures were caused by incorrect choice of fluids and additives. Success and failure were variously defined depending on the well. Matrix acidizing a previously dry exploration well was judged a success if the operation established enough production to permit a well test and possible evaluation of the reservoir. The success of a production well was more closely aligned with achieving a spesific skin improvement. 

Reasons for poor field operation centered on the technique of bullheading, in which acid is pumped into the well, pushing dirt from the tubing and whatever fluids are below the packer, often mud, directly into the formation. Bullheading can be avoided by using coiled tubing to place acid at the exact depth required, bypassing dirt and fluids already in the well. 

What helped AGIP identify and correct the failures, though, was reliable real-time monitoring of each job, particularly the tracking of skin. If skin improves with time, the job is presumably going roughly as planned and is worth continuing. If skin stops improving or gets worse, then it may be time to halt operations. The problem initially was the poor quality of field measurements, traditionnaly simple pressure charts. Then in 1983, digital field recording of well-head pressures was introduced. Today, fluid density, injection flow rates, wellhead and annulus pressures are recorded and analyzed at the wellsite. 

Three methods have been proposed to monitor skin. In 1969, McLeod and Coulter suggested analyzing the transients created before and after treatment fluid injection. The analysis was performed after job execution and therefore not intended to be a real time technique. 

Most recently, Laurent Prouvost proposed a method that takes into account the transients and can be computed in real time using the Dowell Schlumberger MATTIME system. Their method takes the measured injection flow rate and, using transient theory, computes what the injection bottomhole pressure would be if skin were fixed and constant - it is generally chosen to be zero. This is continously compared with the actual bottomhole pressure. As the two pressures converge, so it can be assumed that the well is cleaning up. Finally, the difference in pressures is used to calculate skin.

The key to real-time analysis is accurately knowing the bottomhole pressure. This can be estimated from the wellhead pressure or, if coiled tubing is used, from surface annulus pressure. The most reliable method, however, is to measure pressure downhole. This can now be achieved using a sensor package fixed to the bottom of the coiled tubing.

Evaluation should not stop once the operation is complete. The proof of the pudding is in the eating, and operators expect to recoup acidizing cost within ten to twenty days. From the ensuing production data, NODAL analysis can reveal the well's new skin. This can be compared with new predictions obtained by simulating the actual job - that is, using flow rates and pressures measured while pumping the treatment fluids- rather than the planned job. Understanding discrepancies between design and exectuion is essential for optimizing future jobs in the field. 


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