During completion and workover operations high rate fluid loss isencountered in many wells due to the presence of highly permeable and naturallyfractured, depleted formations. Several methods to obtain temporary plugginghave been studied to select the most versatile technique for different fieldconditions. In addition to the laboratory results, field trials have beenperformed for detailed and comparative evaluation of loss control compositions.These compositions included polymers and sized calcium carbonate systems,polymers and sized micronized (fibrous) cellulose combinations, polymers andsized salt systems (medium and high temperature formulations), crosslinkedpolymer gel plugs, and delayed swelling, stabilized (extended life) polymersystems. The role of fluid chemistry in prevention of formation damage,extension of gelation temperature, and temperature stability was alsoinvestigated. The temperature and differential pressure of the formations(sandstone limestone, conglomerate, metamorfite, etc) varied between 60-170°C,and 1-15 MPa respectively. Fluid compositions without imposing severepermeability damage were selected, which can be broken down chemically. Casestudies of field operations performed in Hungary are also presented.
During completion and workover operations high volume fluid loss may beencountered due to the presence of highly permeable (matrix and/or fractured)formations. This problem is especially critical in case of depletedreservoirs.
Complete losses are increasingly common in our recent field experience.Current fluid technology offers various methods in combating loss ofcirculation. We have conducted an extensive laboratory and field testingprogram to evaluate several additive/fluid systems to aid in solving high-rate,through perforation fluid loss problems encountered in completion and workoverjobs.
Our work concentrated on medium-temperature (100 - 140°C) matrix-type losszones, however the results are applicable to other conditions (high temperaturefracture-dominated formations, low temperature underconsolidated sandstones,etc.) as well. Several combinations of additives having either bridging orfiltering effect were evaluated, as we needed a plug with adequate mechanicalstrength to withstand very high differential pressures, and with good filteringefficiency to minimize fluid invasion.
Scale dissolvers have successfully been used to restore well productivity intwo Statfjord Field wells suffering from scale induced formation damage.Combined with scale inhibitor treatment further production loss has beenavoided. The dissolver efficiency towards BaSO4, and SrSO4, is stronglydepending on high pH (pH> 9-10) in the treatment slug. Two different scaledissolvers have been tested, and are found to have equally good performanceregarding dissolution capasities and effect on production. Well case historiesand details about job design and production data before and after thetreatments are documented. Combined scale dissolver and scale inhibitor squeezetreatment is implemented as the current scale treatment strategy for theStatfjord Field.
The Upper and Lower Brent reservoirs in the Statfjord Field are developedwith a row of sea water injectors, completed below the oil/water contact, todisplace oil up structure to the east toward a row of oil producers near thecrest of the structure. Key information about the Statfjord Field is listed intable 1.
Pyrobitumen is a black solid insoluble carboniferous deposit derived fromthermal degradation of hydrocarbons. Although the organic material has beenobserved in carbonate rocks world-wide, very little is known about its effecton some basic rock properties such as porosity, permeability, wettability, andpotential for formation damage. All of these properties play significant rolesin hydrocarbon recovery processes.
In this study, the amount and distribution of pyrobitumen were determinedusing a newly developed ashing method. Potential formation damage, which can becaused by entrainment of pyrobitumen during waterflood, oil production and acidstimulatio, was examined using coreflood experiments. Electrophoretic mobilitymeasurments and surfacant adsorption coreflood experiements were performed tostudy the effects of pyrobitumen on the surface propeties and adsorptionbehaviour of these carbonat rocks. The effect of pyrobitumen on the wettabilityof carbonate rocks was investigated in the contact angle experiments.
Objectives and Scope
Pyrobitumen, a solid, black, bituminous material, has been observed insignificant quanities worldwide, especially in Albetra Devonian carbonates. Thesolid hydrocarbons are present in the carbonate rock as either pore-filling orpoe-lining material within the vugular and the intercrystalline pore network.Although pyrobitumen has been observed in Alberta carbonate reservoirs, verylittle is known about its effect on some basic rock properties such asporosity, permeability, and wettability. All of these properties may have asignificant influence on hydrocarbon recovery processes.
Curable resin-coated proppants (RCP) have been used to minimize proppantflowback from propped hydraulic fractured oil and gas wells for years, yetproppant backproduction is still reported to be a major operational problem.The industry cannot currently explain why some hydraulic fractures propped withcurable RCP produce proppant back while others containing only uncoatedproppant do not produce any proppant back.
This paper presents results of a study done to help determine screeningconsiderations for curable resin-coated proppants. The study involved curingand crushing proppant plugs under a variety of conditions ranging fromfrac-and-pack applications in shallow wells to fracturing applications in deephorizontal wells. These tests were conducted to identify suitable RCPs forgiven applications.
The unconfined compressive strength (UCS) of proppant plugs cured in thetreatment fluid at reservoir temperature with closure stress applied, iscurrently used as the screening criterion for curable RCP. The UCS needs to beas high as possible while the same resin coating should not consolidate theproppant while left in the well after a treatment without closure stressapplied. This study demonstrates that at least six data points are needed toobtain a representative value for the unconfined compressive strength (UCS) ofproppant for any one set of conditions. Although several studies of factorsaffecting the performance of RCPs have been presented in the literature, theconclusions in these studies are generally based on limited data for one set ofconditions and are, therefore, often questionable.
In addition, the effect of cooldown and subsequent heatup on RCPs after atreatment has not been considered previously as a factor in proppantbackproduction. This paper demonstrates that this temperature effect is animportant parameter to consider. Stress cycling has been identified as one ofthe failure mechanisms for RCP in experiments. These experiments were conductedat ambient temperature with proppant packs cured at temperatures between 160and 200°F (71 and 93°C). We conducted similar experiments at simulated in-situconditions to verify whether the mechanism was still effective for theseconditions. We found that the addition of thermoplastic film material to RCPcured at 300°F (149°C) increased its resistance to stress cycling.
The placement of acid over the entire wellbore interval can be the key to successful stimulation treatments in wells with long (often horizontal) completion intervals. This paper discusses computer simulations performed to determine how fluids are distributed in the wellbore during bullheaded and circulated acidizing treatments. One of the novel aspects of these stimulations is the inclusion of wellbore effects arising from the transient flow of acid and diverter along the wellbore. The results give an insight into a possible cause of some of the poor stimulation performances observed in the field when typical volumes of low-viscosity acids were injected without diversion or selective-placement techniques. Such situations can result in the acid coming into contact with only a small fraction of the treatment interval. The simulations also show how viscosifying the acid could have improved the stimulation performance.
This paper outlines the basic concepts of the simulations and some of the general trends observed from the results. In particular, the inclusion of transient wellbore flow calls for the modification of recently published guidelines for various diversion techniques.
Horizontal wells are widely recognized to have advantages over vertical wells. They are popularly used, for example, to exploit thin oil-rim reservoirs, to avoid such drawdown-related problems as water/gas coning and sand production, and to extend wells by means of multiple drainholes. Yet their potential productivity improvement factors often fail to materialize in practice as a result of the skin (permeability-impairing near-wellbore damage) caused by drilling and completing the wells. Recent investigations have shown that skin can be as detrimental to the performance of horizontal wells as it is to that of vertical wells1-3. In fact, horizontal wells often experience higher skin values than conventional wells, as a result of the slotted liners or barefoot completions that are employed in such wells. Unlike the earlier industry standard of cased and cemented completions, these horizontal-well completions lack perforations. Field and laboratory experience has shown perforations to be an effective means of bypassing the impaired zone.
For that reason the avoidance of near-wellbore permeability impairment, e.g., through the use of new drilling fluids and under-balanced drilling and completion, has been emphasized in the drilling of openhole horizontal wells4-6. A significant research effort over the last few years has also involved the experimental determination of the best clean-up procedures to follow prior to production7,8. This interest in wellbore cleaning has led to a resurgence of matrix acidizing, which over the years has proven to be a cost-effective method of removing impairment in the near-wellbore area of vertical wells. The stimulation of horizontal wells by means of matrix acidizing, however, has often met with limited success.
Data collected during gravel packed completions may be analyzed to evaluate the impact of specific completion practices on well performance. Operations where gathering data is critical are: (1) during the initial flow and perforation cleanup after underbalanced perforating, (2) during prescribed injection tests prior to gravel packing, (3) during periods in which fluid is being injected into the formation (pre-packing perforations, fluid loss after perforating, fluid loss after gravel packing), and (4) during stabilized flow after the well is brought on line. This data can be used to calculate an approximate value for kh (md.ft.) and an instantaneous completion efficiency at different stages of the completion. By comparing these instantaneous completion efficiencies, the damage contribution of certain operations and the damage prevention aspects of other operations may be quantified. This methodology should provide a valuable resource to those pursuing continuous improvement in well completion operations, particularly those involved in sand control.
This paper describes the methodology and results of a series of testsconducted on HydroxyEthyl Cellulose (HEC) gel to determine its effects onreturn permeability. HEC gel is widely used in the oilfield as a carrier fluidin gravel packing operations and is generally considered to cause minimalformation damage. However, results of this study indicate that even when HECgel is efficiently removed from the formation, interaction between the fluidand the formation can result in reduced return permeability. Therefore,particular care must be given to quality control and mixing procedures tominimize potential formation damage.
HEC gel break-back procedures used by oilfield laboratories for returnpermeability measurement are based on displacement studies related to reservoirengineering. In these tests, flow through a Berea core is maintained atconstant pressure and later, after introduction of the test fluid, the changein permeability is calculated as a percent of the initial permeability. Inthese cases, any resulting loss of permeability was assumed to be caused by HECgel trapped in the formation.
To insure complete HEC degradation over time and temperature with andwithout the presence of formation minerals, seven different breaker systemswere evaluated to select the most efficient system. This study concludes thatdamage caused by HEC residue is minimal compared to the damage caused by theinteraction of the fluid and the rock minerals present in various formations.The results of our investigation also indicate that the performance of breakersis influenced by the presence of formation minerals.
This paper will present experimental data of HEC gel break-back in thepresence of formation minerals as well as the testing of chemical additivesdesigned to minimize damage and deliver improved return permeability.
Studies indicate that HEC workover, packer, completion and gravel packfluids cause minimum formation damage and yield high productivity. Viscositybreakers (e.g. enzymes, oxidizers, acids) are particularly useful duringworkovers and gravel pack operations. A fast breaker, consistent with a verylow level of insoluble residues, is essential in preventing wasted rigtime.
Artificial neuron network (ANN) models are designed to emulate human information processing capabilities such as knowledge processing, speech, prediction and control. The ability of ANN systems to spontaneously learn from examples, reason over inexact and fuzzy data, and provide adequate responses to new information not previously seen, has generated increasing acceptance for this technology in the engineering field and resulted in numerous applications. A preliminary investigation into the use of this novel technology is presented towards predicting formation damage by quantifying wettability and two-phase relative permeability of oil reservoirs.
An artificial neuron network model based on the Back Propagation technique is trained with a number of variables from experimentally established relative permeability (relperm) curves. The reservoir core input data covers an extensive range of porosities and permeabilities from different lithologies having diverse wettabilities. The trained model is then tested with only a couple of easily obtainable input variables such as the Swc and Sor and predictions are made on the wettability and relperm curves. A change or shift in the relperm curves is associated with changes in wettability, and perhaps to formation damage in the drilling process.
The wettabilities of the rock-fluid system are predicted to within 90% of the experimentally determined values. The relperm curves, particularly the end-points are predicted to within 85% of the measured results. The accuracy of the predictions are significantly enhanced with model training using more precise reservoir data and better defined formation lithologies. Neural networks have immense potential in predicting relperm curves and thereby assessing formation damage in reservoirs.
Formation damage is usually associated with the decrease in permeability of hydrocarbon reservoirs. The resulting permeability changes directly influence the relative permeabilities of the hydrocarbons in-place. The important reservoir parameter, wettability, may also be altered, depending on the type and cause of formation damage. Drilling and completion fluids, and additives, are known to alter wettability around the wellbore, due to improper fluid and/or additives selection. Accurate prediction of the wettability and the relative permeabilities at any instant will therefore provide a valuable tool for formation assessment and the ensuring changes due to possible formation damage.
The evaluation of a present acid injection profile used in acid flowbackanalysis is an important tool for optimizing acid treatments, as it affects theacidizing process by improved results of hydrocarbon production rather thansubjecting the well to yet another optimized acid treatment in the future. Inthe standard method of acid flowback analysis, the engineers interpret theplots of the return fluid ionic content versus return volumes at certainincrements i.e. every 10-20 bbl. In our work. we have found that this methodmay pose more questions than it answers.
In order to simplify the acid flowback analysis method and provide a moredefinitive interpretation. we introduced a simple derivative technique in theanalysis of the dissolved formation or the scale dissolved ionic content. Inthis technique the ratio of incremental ionic concentration per incrementalproduced volume (the derivative) was plotted against the cumulative producedvolume. The significance of using this technique is that the derivative ofionic concentration with respect to the produced volume is very sensitive tothe minute changes in the ion concentration per unit volume or cumulative acidflowback volume.
We applied our method to two wells, which we shall call them wells # 1 and#2. In the case study of well # 1, first we found that the acid stimulationtreatment dissolved significant amounts of material containing Potassium,Sodium. Magnesium, Iron, Aluminum, Silicon, Barium. and Calcium. But thetreatment did not remove the Zinc completely. The source of Zinc could havebeen either the formation of zinc hydroxide from heavy brines or the 60% Zinccontent of some pipe dopes. Incomplete dissolution of material containing Zincresulted in an inefficient treatment. Consequently, the treatment was able torestore only the original production rate but failed to result in any increasein incremental production. Secondly. from the disordered dissolution profilesof Magnesium, Calcium and Barium, we found that these three elements existed inthe formation as individual mineral rather than scale.
During the gravel packing and fracturing processes in deviated wells the flows can follow complicated three-dimensional paths in the treating string. In this paper we present the formulation of a three-dimensional numerical model of fluid and solids transport for evaluation and design of these completion events. The simulator tracks the slurry flow from the surface, throughout the wellbore, and into the perforations. It treats fluid return and loss into the formation. The model simulates fluid displacement, gravel settling, dune formation, bridging, fluid flow through packed solids and flow into and out of screens.We present validation results against laboratory and field data for various fluids, deviations, pumping rates, and solids loading.