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Introduction This chapter is organized to help perform acidizing on a well candidate in a logical step-by-step process and then select and execute an appropriate chemical treatment for the oil/gas well. The guidelines are practical in intent and avoid the more complicated acid reaction chemistries, although such investigations and the use of geochemical models are recommended for more complicated formations or reservoir conditions. Effective acidizing is guided by practical limits in volumes and types of acid and procedures so as to achieve an optimum removal of the formation damage around the wellbore. Most of this chapter is an outgrowth of field case studies and of concepts derived from experimental testing and research. Justification for the practices and recommendations proposed herein are contained in the referenced documents. The reader is referred to the author's previous papers on matrix acidizing for references published before 1990. Concepts and techniques presented have ...
Successful matrix acidizing depends upon: (1). good evaluation of candidate wells using (a) completion and production histories, (b) producing well flow analysis (nodal analysis) and (c) formation composition analysis, (2). design for effective coverage of all damaged perforations, (3). selection of solvents, acids and acid compositions to prevent or reduce incompatibilities and (4). effective well preparation and job supervision.
During the 1980's research and development in matrix acidizing focused more on the prevention of incompatibilities and proper on-site execution and less on chemical product development. Advances in well flow analysis (nodal analysis) have also improved the selection of acidizing candidates and the evaluation of acidizing success. On-site supervision has been assisted by improved data gathering equipment and on-site computing to better monitor the progress of damage removal by acidizing. Improvements continue to be made in better acid coverage of damaged perforations through the use of diverting agents and mechanical isolation devices. This paper will focus on these significant factors for successful matrix acidizing.
SELECTING SUCCESSFUL ACIDIZING CANDIDATES
John Gidley presented the results of an extensive statistical review of one company's acidizing success in sandstone reservoirs in the U. S. He found that only 54% of 507 wells increased in production following mud acid stimulation (his production following mud acid stimulation (his Table 3). Our past experience supports these findings. Where better evaluation and quality control have been implemented, the percentage of successful treatments has improved to 75 to 90%. Such a program was developed by Brannon, Netters and Grimmer who successfully acidized 35 of 37 wells (95% success) for an average production increase of 343 BOPD. Other areas and formations still suffer from poor acidizing responses which implies that opportunities for technology development still exist.
Producing Well Analysis Producing Well Analysis The greatest cost savings in matrix acidizing result from better engineering evaluation of acidizing candidates. A good matrix acidizing candidate is a well producing from a formation with permeability greater than 10 mds, and whose permeability greater than 10 mds, and whose permeability in the near well bore or near permeability in the near well bore or near perforation region has been reduced by solid perforation region has been reduced by solid plugging. This plugging is either mechanical or plugging. This plugging is either mechanical or chemical. Mechanical plugging is caused by either (1) the introduction of suspended solids in a completion or workover fluid or (2) the dispersion of insitu fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids which precipitate solids. One example of formation precipitate solids. One example of formation damage by a solids-contaminated fluid is shown in Figure 1. An unfiltered produced brine was used to kill the well during a workover to repair a tubing leak. In this example formation damage is obvious in the reduced productivity immediately after the workover. This lowered productivity persisted until an acid treatment removed the damage. Many times the analysis of a damaged condition is not so obvious.
Often acidizing candidates are selected on the basis of offset well comparisons. The productivities of offset wells are compared, and productivities of offset wells are compared, and the poorer performing wells are selected for acidizing. Many times this selection is made without sufficient well testing.
Pretreatment analysis, job planning, and well preparation lead to acidizing success in sandstones with permeabilities greater than 50 md. Formation mineral analysis improves success in sandstones with lower permeabilities. Injection pressure responses to acid injection provide data for onsite decisions.
Many papers have been written about specific pro ducts for acidizing sandstone formations. Most often these products are designed to correct specific problems and are primarily based on laboratory research in sandstone cores. Very little has been written about evaluating problems that exist in oil and gas wells completed in sandstone formations. Identifying problems in real wells which can be solved with specific products is an important part of the overall acidizing program. This paper will attempt to provide insights into identifying problems and selecting the best product or process to remove the specific damage.
Also, many papers have been written about specific acidizing design models. Most of these papers predict the spending of HF as it penetrates the formation and sometimes the permeability increase. These papers show that regular 3 percent HF only penetrates formations about 6-12 inches before the HF completely spends. More recent retarded HF acids have achieved deeper penetration. It has been the authors experience that the volume of acid predict by these models is not the real key to successful acidizing, but rather it is the control of injection into all the perforations in the formation that determines success. Moreover, some formations respond well to HF acids and others can be damaged by the application of either HF acid or HF acid. This paper will discuss the reasons for this with recommendation on which wells are potential HF acid successes and which wells should be stimulated in another way.
PLANNING THE ACID TREATMENT
The first step in planning an acidizing treatment is to determine whether the well is damaged and how much. One should determine the production potential of the well to see whether removing the damage will provide enough production increase to pay for the acid treatment in a reasonable period of time.
The question to be asked in evaluating well damage are: (1) when was the well damaged, (2) how was it damaged, and (3) what caused the damage. Production history curves often show when a well was damaged unless the damage occurred during drilling and completion. it is important for the engineer to understand all aspects of formation damage in order to interpret the records that exist in well files.
Formation Damage Analysis
Certain types of damage consistently occur in the three major phases of a well's life: (1) drilling and cementing, (2) completion and (3) production. Information exists or can be obtained to show whether damage could have occurred and its mechanism.
Drilling and Cementing Damage
One of the most important sources of damage is that from drilling mud filtrates which usually have a high pH. Several authors, have shown that pH's above 11 are damaging to formations with significant quantities of clay, i.e. 5-20% by weight of clay. A recent paper, showed the variation of permeability with pH. This curve can be used as a first estimate to determine the reduction in permeability by invasion of formations with high pH mud filtrates.
Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area,these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering.
Many excellent and useful papers have been written on the subject of matrixacidizing. Included in this article is an extensive bibliography that should beuseful to the engineer in the design and execution of a matrix acidizingtreatment in limestone or sandstone formations. The first matrix acidizing jobswere very successful in stimulating oil production in carbonates. However, mostof the recent attention to matrix acidizing concerns sandstones and the use ofvarious hydrofluoric acid systems. Matrix acidizing in carbonate formationsstill is beneficial in high-permeability, damaged formations (50 md or more).Damage can occur during drilling, completion or production of a well. Incarbonates with permeabilities less than 10 md, acid fracturing generally isused because much greater stimulation is obtained with long, acid-etchedfractures in low- permeability reservoirs. Although the acid systems used insandstones and carbonates differ, the same practices apply to both.
Well Performance (Need for Acidizing)
Successful acidizing depends on the presence of damage and its location andintensity. The closer the damage is to the perforations, the more easily acidcan get to it. Compacted or crushed zone damage from perforating overbalancedcan be removed easily by acid, since only about 1/2 in. [1.3 cm] of damage mustbe removed directly around the perforation. Precipitates from previous acidtreatments more than 1 ft [0.3 m] from the wellbore in sandstone or 5 ft [1.52m] in carbonate will be either impossible to reach with matrix acidizing or tooexpensive to treat. Deep solid plugging, will be corrected more effectively bycreating a conductive fracture through the damage either by sand fracturing oracid fracturing. Nonplugging damage (e.g., oil wetting) may be several feetdeep around the wellbore, but reverse wetting surfactants can penetrate andreverse the formation to a water-wet condition at reasonable cost. Oil wettingdamage usually is less severe than solid plugging damage, so correctivechemicals can reach the affected area easily.
High-permeability formations (those with 100 md or more) seem to bedominated by either formation damage or tubing size flow restrictions. This isparticularly true of gravel-packed offshore wells. When well flow is markedlyless than similar wells in the same reservoir, most of the drawdown probably isoccurring at the wellbore through a small zone of reduced permeability. Mostrecent gravel-pack-damage research has focused on gravel-packed tunnels andquality of the gravel in the tunnel. Current techniques have improved so muchin recent years that gravel-packed tunnels usually offer little flow resistancewhen perforating density is adequate. Nevertheless. reduced flow throughgravel-packed wells still occurs. Current research focuses on (1) incompletelypacked tunnels and (2) formation-sand damage near the entrance to the tunnels.Torrest and Stein described gravel shifting in tunnels when the gravel pack isnot packed tightly during placement. Damage to formation sand before gravelplacement will cause premature pressure outs resulting from viscous fluidsentering damaged or reduced permeability near the perforations. Because of highpressures, pumping may be halted before the gravel has concentrated adequatelyin the perforation tunnels. If the pumping stops too soon, the tunnels will befilled only partially with quality gravel. When the well is produced, formationsand will enter the tunnels, bridging on the gravel inside the tunnel andpacking the partially void tunnel with formation sand, which is much lower inpermeability than the gravel. As the formation sand fills the tunnels. thepressure drop through the completion increases and the flow rate declines.
Abstract Formation damage occurs during the lifetime of many wells. Loss of well performance due to formation damage has been the subject of several review articles. Fines migration, water, emulsion blockage, inorganic scale, asphaltene, and other organic deposition are a few mechanisms that can cause formation damage. The present paper discusses new formation damage mechanis ms that are caused by various chemical treatments. These include: adsorption-type scale squeeze treatments (phosphonate-based inhibitor), solvent treatments (a neat mutual solvent) to remove water blockage in a tight carbonate reservoir, and regular mud acid (HCl:HF at 12:3 weight ratio) to remove drilling mud filter cake in sandstone reservoirs. These treatments were designed to remove a known form of formation damage. However, they created new forms of formation damage, which resulted in a significant decline in the performances of several wells. Case studies of new damaging mechanisms that resulted from various chemical treatments are discussed in this paper. Details of lab and fieldwork that were performed to identify the damaging mechanisms and determine its impact on well performance were addressed. Finally, the paper highlights the remedial actions and field application that resulted in restoring the performance of various wells without affecting the integrity of the formation. Introduction Formation damage can occur during the lifetime of all wells starting from drilling, completion, production, and stimulation. Basically, it causes loss of well performance, and usually requires an expensive treatment to remove such damage. Formation damage can be divided into two main categories: mechanical and chemical damage. Mechanical damage occurs when particulate solids, emulsion, asphaltene, or inorganic scales physically plug the pore spaces. A typical example of formation damage due to suspended solids occurs in water injectors. Oil droplets can also cause damage to disposal wells, especially in the presence of suspended solids. In both types of wells, suspended solids and oil can plug the formation and cause loss of well injectivity. Another important example of mechanical formation damage is injecting or producing oil or gas wells at high rates. In this case, the fluids will exert high drag forces on clays and feldspars, which can dislodge fine particles. The mobilized fine particles accumulate at the pore throats, and cause formation damage. This type of damage occurs in sandstone reservoirs, which contain kaolinite and other migratory clay particles. Formation damage due to chemical means occurs in many reservoirs. Injection of low salinity water into a sandstone reservoir with high salinity water is a typical example. In this case, the lower salinity water will trigger clay swelling and fines migration. Both can cause severe formation damage, especially in tight formations. Another example is the injection of incompatible water. If the injection water contains high sulfate content (seawater is a typical example) and the formation water contains high concentrations of calcium, strontium, or barium ions then the sulfate salts of these cations will precipitate in the formation and may cause severe formation damage. An example of mixing incompatible waters occurs when disposal waters which typically contain high hydrogen sulfide content are mixed with injection water, which contains dissolved iron. Iron sulfide species will precipitate upon mixing of these two waters, and can cause severe loss of injectivity.