Abstract Most horizontal completion methods used for Resource Plays are very challenged to either effectively place or to keep proppant in the near wellbore area; in fact, this seems to rarely be a major goal of our completion plan and/or fracture treatment designs, but can we afford to continue this? Few Resource Plays have the high rock complexity found in the Barnett Shale; each play should be developed using completions and designs relative to its own formation properties, not simply clone the Barnett completions and stimulation designs. Too often operators have chosen to force-fit what they have seen to be successful in the Barnett to a much different set of formation conditions and properties. The pre-Barnett successes using waterfracs in tight gas non-complex formations, where the poor formation responses often seen after using large gelled fluid frac treatments on tite gas zones are now believed to be due to the severe cleanup problems from gel. Tight formations may not have adequate energy to effectively clean a large mass of gel from the proppant bed porosity, especially if underpressured. With only partial cleanup of these costly treatments, operators looked for improvements in production or reduced cost (Mayerhofer et al. 1997). Although the WaterFrac treatments placed much less proppant, with only water in it, the proppant bed could easily be cleaned to provide near 100% benefit, while gelled treatments of that timeframe placed in tight gas formations may clean up only a small percentage of the proppant placed. With the Barnett Shale, it turned out to be much more than that, as it is quite different from any other major formation being significantly drilled in the mid- to late 1990’s. The key was the massive number of small fractures present, many of which were in a "healed" state prior to fracturing. Mitchell Energy finally found the secret to unlock this complexity: Large volume, high injection rate WaterFrac treatments! The nanodarcy range insitu perm of the rock must have a massive volume of enhancement to that permeability, and they could only be adequately activated using these large volume high rate Waterfracs. By not placing any gel into this complex system, even without propping them open they could perform as a massive "gathering system" to get more gas back to the propped fractures. Soon after the Barnett proved economic with vertical completions, by moving to long horizontal completions and using large volume, high rate multi-stage fracturing applications, the Barnett proved to suddenly be one of the highest returns on investment (RoI) opportunities of the time. It soon became the field with the most rigs operating in North America. This new completion concept, using long lateral completions combined with massive multi-stage fracture stimulations, we will christen as the Shale Completion Method for discussions in this paper. However, although we now are successfully completing economic horizontal wells in many other ultra-low perm source rock formations, there seems too often be short cuts taken in many areas that can challenge continued success away from the sweet-spots of the field, and we even accept leaving much of the recoverable hydrocarbons still in place even when the well may achieve acceptable economics. The most obvious stimulation related shortcoming is that Waterfracs have often proved to be quite inadequate as the only stimulation fluid, as only a few of these later fields have formations where we can generate massive complexity when we fracture stimulate. Fortunately, we often can develop some limited degree of complexity, and even though most all of these new source rock plays have sub-microdarcy permeability, they typically will be 10- to 30-fold higher than most Barnett shale. Operators soon moved the Shale Completion Method to the oil bearing Bakken shale in North Dakota, and soon after many more rigs followed. Next, the Shale Completion Method to low/very low perm conventional plays, with the Granite Wash in the Anadarko basin in the Texas Panhandle and western Oklahoma being an early poster child, further showcasing how old fields could be returned to boom-time drilling prospects. Now we found ourselves needing to place fractures with far more conductivity than we needed for the Barnett shale, and needed to use fracturing fluids that could effectively place traditional proppant sizes and at least moderate proppant concentrations. In 2008-09, a significant economic downturn suddenly caused gas prices to tumble, yet global economic factors kept oil prices from falling proportionally, and operators throughout North America were forced to reduce gas well drilling and turn to oil or liquids-rich gas plays. These are plays where we need effective fracture conductivity to produce commercial rates. Today, whether producing from RoI challenged dry gas plays, moderate-RoI gas liquids plays, or (potentially) higher RoI oil plays, all facets of our operations will either be a contributor or detractor from achieving effective fracture conductivity. This starts with initial well location choice and continues through to our long term production methods. The oil and gas plays throughout North America each need to be drilled/completed/stimulated/produced using procedures best suited to each individual play, not copied from somewhere else it appears to be successful. Achieving effective conductivity in our fractures, and ensuring those fracs have adequate connection to our wellbores is a primary factor to maintaining attractive RoI’s and to keep drilling. In this paper we will mostly look at how we can best achieve this in addition to simply using the correct proppants and fluid systems. We can create challenges to delivering effective conductive fractures before we even spud the well and then create added challenges during drilling and add even more before it is time to try to actually place our fractures into our formations.

Abstract After 1970, the technology of hydraulic fracturing began to quickly accelerate, especially as to the industry focus on fracture conductivity. We saw a transformation in our frac fluids as we moved away from crudes and thin water gels to higher viscosity emulsion systems, foamed gels, and even crosslinked gel systems that could deliver significantly more proppant as we chased after better fracture conductivity. Using these more viscous gels we moved to "Massive Hydraulic Fracturing" of tight gas sand formations. This grew to multi-million pound proppant placements as the age of crosslinked gels began to dominate most of the fracture stimulation landscape as we tried to place very long, highly conductive fractures. However, the decade of the 1970’s also had Claude Cooke showing us that sand was a very limited proppant for deeper wells, and then later showing that gel residue could seriously reduce insitu fracture conductivities! (Cooke 1973; 1975; 1976; 1977) During the early 1980’s North America experienced the greatest rig activity ever, but then the mid-80’s gave us the greatest crash the oilfield had ever seen! Fortunately, this also resulted in our industry laboratories having the time to upgrade testing equipment and procedures to "realistic" test conditions for evaluation of packed proppant bed conductivity. This meant longer testing times, high temperatures, and with exposure to frac fluids. This research would subsequently launch the search for better gel breakers and lower residue gels (which continues today). Unexpectedly, in the 1990’s a few operators in tight sandstone applications in East Texas started re-inventing Slick Water fracs (WaterFracs), placing only 15-20% as much proppant as crosslink gel fracs, yet claiming equal or better overall economics. To add further consternation, George Mitchell found another application for WaterFracs and eventually showed the world that a hydrocarbon-source shale formation, the Barnett, can actually be a commercial producer itself. During the early 2000’s, the combination of long horizontals, and extreme multi-stage hydraulic fracturing (mostly using Waterfracs) turned the Barnett Shale into the launching pad of our present-day madhouse search for the next great shale play to chase. It is clear that long horizontal completions and WaterFrac stimulation methods have played an important role in opening the door to economic success in the numerous "resource plays" (i.e. shales). In this paper we will investigate if WaterFrac treatments are violating or upholding (?) one of our most significant fracturing beliefs: Fracture Conductivity should be optimized. Until we moved to the ultra-low formation permeabilities, we would generally say we should try to maximize our conductivity, but with WaterFracs designs it often seems we may instead be minimizing it, and this will be discussed here.

Abstract A proliferation of massive new resource rock (shale) gas fields has come on-stream in the past several years. This has significantly increased gas production and, along with an economic slowdown globally, these factors have combined to create a gas glut in North America and a corresponding fall of gas prices. The industry response to these very low prices has been to reduce the number of rigs drilling for gas; many have been redeployed to several promising new (or reinvented) liquids producing "shale" fields, including gas shales making condensate, as well as traditional very low permeability oil formations. The development of a new completion approach quickly transformed the low-permeability sector of gas and oil well completions—drill a long (flat and straight) lateral section through the heart of the reservoir and then complete with transverse hydraulic fracture stimulations at several points along the lateral, just as if each point (perforation set) were an independent vertical well location (i.e., the Shale Completion Model). The industry also adopted as its primary horizontal completion technique a process called "perf-and-plug," in which pumpdown plugs are used with attached multifire perforating guns. At least three and often up to seven separate intervals are perforated and simultaneously fracture stimulated, adding potential challenges to effectively place proppant into all fractures and achieve or maintain near-wellbore (NWB) conductivity. Today’s drilling is now focusing on liquids plays, which make effective fracture conductivity far more important. The ways in which more conductivity can be delivered need to be revisited, be it with additives, proppant selection, or design approach. This paper reviews fracturing state-of-the-art methods for ultralow-permeability liquids-producing reservoirs and shows how fracture conductivity and economic optimization can be better achieved.

Abstract After hydrocarbon prices suffered freefall in late 2008, many North America operators responded by increasing the percentage of horizontal completions in low-permeability oil and gas reservoirs to maximize their return on investment (ROI). The US market soon had more horizontal rigs running than vertical rigs. By the end of 2010, the horizontal-to-vertical rig ratio was ~1.8:1, thus leading to the strengthening of another market trend: low gas prices causing many operators to move as much new investment to oil plays as possible. Very few seem concerned about the future of oil prices except that a controlled rise was needed to avoid excess economic pressure on somewhat fragile economies that depend on oil. Higher prices and many maturing conventional oil fields can only encourage offshore operators to pursue their more marginal oil reserves. However, instead of following the historic offshore methods and models for well completions, operators need to closely examine what has transpired in North America during the past 5 to 7 years. There, drastic changes to completion models were required to profitably pursue low- to very low-permeability reservoirs; first in the gas markets and more recently low-permeability oil reservoirs. The primary focus of the "North America Shale Model" is two-pronged: the first part is to use long horizontal sections, but the second part to consistent economic success has been completions that enhance the ability to achieve both adequate fracturing injection rates and effective isolation of hydraulic fracturing stimulation stages. Simply stated, the horizontal completion must be very "frac friendly" to be economic. This completion model is already beginning initial evaluation for shale (source rock) gas reservoirs on several other continents. However, most recently, this same basic approach has been seen migrating to low/ultralow oil reservoirs in North America. However, much larger promise of reward globally will be offshore. For low-permeability offshore fields, a necessary goal will be to drain significantly more reservoir per well than historic completion methods allowed by using long lateral lengths that are concentrated in only the better part of the reservoir. The more traditional offshore "horizontal" model has been to get 1.4 to 1.5 times more exposure to each reservoir layer (60 to 70o laterals) and to complete in multiple layers to "get oil from all the zones" without significant stimulation applications. A more profitable completion model is to also mimic the most recent North America oil/gas-liquids model: maximize drainage from the zone with the highest production potential—single-zone, long horizontal completions with effective multistage hydraulic fracturing stimulation. Most people comprising the oil and gas industry have come to expect that great oil and gas fields are "discovered." What is now being witnessed is major gas and oil fields that are being "unlocked" through innovation. It is proposed that what has happened during the past decade in the US might only be the tip of the iceberg once operators worldwide start to accept this new completion concept on a global basis.

Abstract Having worked in the field of Hydraulic Fracturing for forty years has allowed the author an opportunity for close observation of several cycles of conceptual applications of hydraulic fracturing. In 1970, the oilfield was using quite a plethora of varying frac fluids from Slick Water to heated asphalt, gelled diesel, emulsion frac fluids, linear gels, and a few crosslinked fluids, although there was some separation between applicable fluids for gas reservoirs and oil producers. By the mid-1970’s we had witnessed the death of heated asphalt as a frac fluid while emulsion fluids and Slick Water fracs were mostly put out to pasture. The age of the crosslinked gels had begun to dominate most of the fracture stimulation technology landscape, mostly because it was judged that this fluid type was able to suspend and place high concentrations of proppant. The emphasis on achieving high Fracture Conductivity with more effectively propped fractures became dominant. The 1980’s saw the industry fracturing technology and laboratory testing migrate toward more realistic test conditions for evaluation of packed proppant bed conductivity, especially with longer testing times, using elevated test temperatures, and by the latter part of the decade to incorporate the presence of frac fluids and their residue. However, in the late 1980’s, a few operators in tight sandstone applications in East Texas started re-inventing Slick Water fracs. Even though pumping rates and treatment volumes were 2x- to 4x larger than previous crosslinked gel fracturing treatments, they typically were placing only 15–25% of the proppant volume, yet claiming improved well economics. To add further consternation, in the next decade, George Mitchell found a unique application in the Barnett Shale for Slick Water fracs and eventually showed the world that some of these hydrocarbon-source shales can actually be commercial producers themselves. This paper will discuss much of the "frac fluid history" mentioned above, review historical highlights of laboratory fracture conductivity testing and field applications trying to illustrate the need for high conductivity as investigators began finding much lower predicted conductivity as they began seeking to emulate insitu reservoir conditions. Back then and still today, we continue to ask: Are we abandoning one of our most significant beliefs, Fracture Conductivity is King, every time we use Waterfracs?

Abstract During the past 5+ years, North America operators have increasingly turned to horizontal completions in low permeability oil and gas reservoirs to maximize their Return on Investment (ROI). As hydrocarbon prices suffered a freefall in late 2008 to mid-2009, this further forced operators to continually evaluate both cost and effectiveness of various completion and stimulation options. In April 2008 the Baker Hughes U.S. rig count for vertical drilling was twice the horizontal rig count, but after the price collapse we soon had more horizontal rigs running than vertical ones, with the June 2010 ratio being ∼1.7:1 while only four years ago the U.S. had 2.5 vertical rigs for every horizontal rig. Globally, the trend toward horizontal drilling of low permeability oil and gas reservoirs is slowly increasing, with some of the lower permeability onshore and offshore fields also following this trend. As operators see many of their current horizontal completions in moderate to low permeability reservoirs reach their economic limit in only a few years, they often would like to use hydraulic fracturing. However, they are realizing the frac limitations imposed by openhole completion methods and even for highly perforated cemented laterals. Only a few viable options currently exist for effectively placing individual hydraulic fractures at (and ONLY at) preselected locations along the completed lateral section. Unfortunately, often the existing completions limit the fracturing rates that can be achieved. The primary focus of the North America model for horizontal well economic success is completions that enhance the ability toachieve both adequate injection rates and effective isolation of hydraulic fracturing stimulation stages. In some fields, a secondary goal is to drain significantly more reservoir per well by using radical lateral lengths and reduce the number of wells needed. Onshore this concept makes each well much more environmentally friendly, and offshore the economic value is even more obvious. This paper will provide a high-points review of the shale formation completion model. With this model it is critical to select the multi-stage fracturing implementation to be used before the lateral completion method can be chosen. Many current methods require that the installed lateral completion contain specific components that are a part of the stimulation isolation method itself. Also reviewed are a few areas that could further advance the present methodology and offer suggestions for where the industry can consider non-shale applications to further proliferate this methodology outside North America.

Abstract During the timeframe of the mid- to late 1960's, a large number of those working in the Oil and Gas industry were still of the mindset that most hydraulic fracturing treatments were creating horizontal fractures, although the bulk of the technical papers still available from this time period seem to mostly assume or even verify vertical fractures. This view seemed especially prevalent for the numerous sandstone reservoirs that contained thin laminations of shale or shaley sand that seemed to have only very weak bonding to the adjacent sand layers. Many of this group had been present when such a formation was being cored, and observed the core sample simply separate at a (horizontal) bedding plane interface or a thin shale streak when the core would be removed from the core barrel. Many others had read more than one core analysis report containing similar descriptions of this occurring to cores when they were being tested. This misguided "horizontal fracturing concept" was almost always in disagreement with observed pressure data during fracturing operations. Although pressure gradients during breakdown of cased and perforated wells occasionally would approach the reservoir's overburden pressure, fracture extension pressures almost never would. Starting in about the mid-1960's, in an effort to enhance acceptance among the "rank and file" group in oilfield operations that vertical fracture orientation was both expected and actual outcome for almost every well, or at least when deeper than the 1,500 to 2,000 ft range at least one service operator and numerous well operators joined efforts to make rubber impression molds of openhole wellbores immediately after the well had been proppant-fracture stimulated. This was soon followed by adding a method to identify the compass orientation and investigate a more technical purpose: to document the fracture direction. Unfortunately, only a small part of the resulting pictorial data base was ever published into the preserved public domain during the decade of their significant use. This paper will revisit the few known papers within the literature and also data archives preserved in internal company reports and by nearly a hundred photographs of created rubber wellbore molds following openhole hydraulic fracture treatments. These show the resultant propped fracture traces inside wellbores from more than a dozen openhole applications of this simple technology. Such results as fractures (at 4O to 8O angles off of vertical) may only be present inside the wellbore for a few feet, and numerous cases of clear evidence of two and three separate parallel propped fracs present at least at the wellbore wall.

Abstract Like any other business, return on investment (ROI) drives the decision-making processes in the oilfield. The "cut-cost" approach can only be successful when resulting production is adequate. Especially during the past few years, it has been observed that most North America operators using horizontal completions in low-perm oil or gas reservoirs have abandoned the "lowest-cost" approach in favor of a "maximize-production" mindset. Maximizing ROI requires operators to continually evaluate both cost and effectiveness of various completion and stimulation options. With low-to ultralow-perm reservoirs, it has been proven in many fields in North America that using a long lateral section combined with effective, controlled placement of large, multistage propped fracturing treatments can offer the best economic return. Often being combined with pad drilling, the trend continues to be using fewer wells while maximizing the volume of reservoir rock that is fracture stimulated within each completion. There are two interrelated choices that can be combined in several ways to decide how best to complete a lateral section to achieve maximum benefit:Assuming a solid liner is installed, should the operator cement, seal off the annulus into sections by some method, or leave it unsealed?What method should be used to provide frac-stage isolation within the liner? This paper will provide an overview of several different horizontal completion methods and stimulation techniques most commonly used in North America for low-perm reservoirs during the past few years. Included are two different operators' experiences with multiple application methods, but the common denominator is that they included multiwell overviews. Managing risk properly will usually be more than a "current-well" mentality and requires a more field-wide approach, including the cost of completion interruptions from unscheduled/unexpected events. One case takes the comparisons through completion cost and all the way to ROI results, where all wells had more than six months of production. Another case illustrates a situation where the operator concluded that well production is more dependent on reservoir quality than on his choice for completion methods. This case includes more than 75 wells with six to nine fractured intervals per well, comparing not only costs for four methods, but also showing the representative cost variations or overruns. Generally, once a drillsite has been chosen, the most important variable that can be affected is effectively placing individual hydraulic fractures at (and only at) preselected locations along the completed lateral section. Choosing the method to be used is best made before drilling the well, but might have to be revisited if formation properties are different than anticipated or drilling problems result in a wellbore the is a poor fit for the completion plan originally selected. Obtaining effective isolation of stimulation stages is often the primary goal required to achieving adequate production response and effective reservoir exploitation while managing the costs to achieve best ROI on a field-wide basis.

Abstract This paper reviews applications of hydrajet perforating during the past 6+ years specifically as they apply to horizontal and highly deviated completions for both oil and gas reservoirs. Many benefits to hydraulic fracturing through hydrajetted perfs instead of shape charge perforations will often exist. Also, a key feature to more economic applications has been coupling this process with a method that includes multi-stage fracturing operations. This feature can shorten the completion time needed to achieve multistage frac treatments. During this decade, horizontal wells that need fracture stimulation are being drilled deeper and, especially, with longer lateral sections requiring larger numbers of fracturing stages. This has increasingly challenged the limits of conventional jetting systems and methods, while requiring higher pressure limits for the wellhead, treatment tubing, and pumping equipment. Three primary methods for using hydrajet perforating have been part of the surge of horizontal well applications. Listed in the order of their emergence of significant application during the present decade, they are: hydrajet fracturing (HJF), hydrajet perforating, annulus path fracturing (HPAP), and standalone use of hydrajetted perforating (SHJP) followed by conventional wellbore stimulation and isolation applications.

Abstract This paper reviews applications of hydrajet perforating during the past 6+ years specifically as they apply to horizontal and highly deviated completions for both oil and gas reservoirs. Many benefits to hydraulic fracturing through hydrajetted perfs instead of shape charge perforations will often exist. Also, a key feature to more economic applications has been coupling this process with a method that includes multi-stage fracturing operations. This feature can shorten the completion time needed to achieve multistage frac treatments. During this decade, horizontal wells that need fracture stimulation are being drilled deeper and, especially, with longer lateral sections requiring larger numbers of fracturing stages. This has increasingly challenged the limits of conventional jetting systems and methods, while requiring higher pressure limits for the wellhead, treatment tubing, and pumping equipment. Three primary methods for using hydrajet perforating have been part of the surge of horizontal well applications. Listed in the order of their emergence of significant application during the present decade, they are: hydrajet fracturing (HJF), hydrajet perforating, annulus path fracturing (HPAP), and standalone use of hydrajetted perforating (SHJP) followed by conventional wellbore stimulation and isolation applications.

Hydrajet (Abrasive) Perforating Can Improve Success of Fracturing Stimulations Billy W. McDaniel; Billy W. McDaniel Halliburton Search for other works by this author on: This Site Google Scholar Jim Basuki Surjaatmadja; Jim Basuki Surjaatmadja Halliburton Energy Services Group Search for other works by this author on: This Site Google Scholar Loyd E. East Loyd E. East Halliburton Energy Services Group Search for other works by this author on: This Site Google Scholar Paper presented at the International Petroleum Technology Conference, Kuala Lumpur, Malaysia, December 2008. Paper Number: IPTC-12043-MS https://doi.org/10.2523/IPTC-12043-MS Published: December 03 2008 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation McDaniel, Billy W., Surjaatmadja, Jim Basuki, and Loyd E. East. "Hydrajet (Abrasive) Perforating Can Improve Success of Fracturing Stimulations." Paper presented at the International Petroleum Technology Conference, Kuala Lumpur, Malaysia, December 2008. doi: https://doi.org/10.2523/IPTC-12043-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search nav search search input Search input auto suggest search filter All ContentAll ProceedingsInternational Petroleum Technology ConferenceIPTC International Petroleum Technology Conference Search Advanced Search AbstractAt least as early as the 1960s, many well operators knew that hydrajetting perforations, or slots through cemented casing, could often "bail-out" a problem well that otherwise seemed completely resistant to hydraulic-fracturing attempts. However, for more than 50 years of fracturing applications, there was insufficient demand for this process to make it a commodity service, especially before the advent of coiled tubing (CT) services in the 1980s. With very sporadic use, this type of well service was costly because abrasive mixing and high-pressure pumping were both needed, and efficiencies of repetitive use were not developed. Conventional explosive shape-charge perforating was usually lower-cost and seemed sufficient for most wells.As oil and gas prices have drastically increased interest in multi-stage fracturing operations and wells are more often being completed in hard, low-permeability reservoirs, hydrajet perforating (HP) has seen a global resurgence. For many applications, HP can improve fracture-stimulation efficiency and well economics. In a few cases HP has proven to be the only way that effective fracture stimulation could be achieved. There is a growing acceptance among both operators and service companies that hydrajet (abrasive jetting) perforating can result in superior well stimulation. Some newer methodologies have combined HP and hydraulic fracturing into a single, continuous, multistage stimulation method. The use of a larger number of discrete stimulation stages has often provided significant production gains and greater recoverable reserves. Reductions in nonproductive time (NPT) also can allow for reduced well costs, even when more actual fracture stages are pumped.Additional to using HP as a component for multistage fracturing, in many moderately hard and very hard formations operators have proven the value of converting from shape-charge perforating to hydrajetting as a stand-alone operation to avoid severe near-wellbore problems during hydraulic-fracturing stimulation treatments. This often has drastically enhanced stimulation success for many wells. This paper reviews the expanding services and global applications of HP in recent years.BackgroundJetting of carbonate formations in openhole completion has been reported at least as early as 1939. It was not until 1958 that there were oilfield reports of incorporating solid abrasives in the jetted fluid and reporting widespread use for perforating the casing and formation. What preceded the successful move from hydrojetting (w/o abrasives) to hydrajetting (w/abrasives) was the transition to more abrasion-resistant carbide jets (Brown et al. and Pittman et al.). Ousterhout indicated that by early 1961 over 2,500 successful HP jobs had been performed. This was a time when bullet perforating was common, and explosive/shape-charge perforating technique was still in its infancy.There was not always a distinction between perforating and slotting in the very early papers, with the slotting mostly a result of pipe rotation. Today, this would be carefully implemented to avoid severing, or even over-weakening, of the casing. For fracturing through such slots in vertical wells, there would be some concern that a fracture might initiate horizontally, although if a second vertically oriented fracture that intersected the wellbore was to form quickly, this may not be a problem. For horizontal-well applications, rotational slotting could be beneficial when transverse fractures are preferred but would need to be carefully controlled because a parted liner could mean future problems with re-entry to the wellbore below that point. Additionally, excessive rotational slotting could weaken the liner to the point it might collapse with long-term production. Keywords: Upstream Oil & Gas, hydraulic fracturing, multistage fracturing, stimulation, McDaniel, proppant, liner, application, hjaf method, Completion Installation and Operations Subjects: Hydraulic Fracturing, Perforating, Multistage fracturing, Completion Installation and Operations, Completion Operations This content is only available via PDF. 2008. International Petroleum Technology Conference You can access this article if you purchase or spend a download.

Abstract Sometimes we dive too quickly into the smallest of details when trying to plan for fracture stimulation applications in our industry. It has been too often that a frac design engineer will gloss over the importance of unknown or missing reservoir data but spend many hours chasing the "exact-best" value to use for the treating fluid viscosity in the frac design simulator. Some reservoirs we frac routinely and understand how fracturing is best applied, and a few where we can choose the full scientific approach and monitor with microseismic listening. When there is just no chance to know accurate reservoir data, we may have few design options. However, it seems more often the case that the "frac design world" simply does not search out important data available within the geologist-geophysicist realm. The available pseudo-3D and numerical 3D frac design simulator software available to us can be used as a crutch instead of a useful tool. We can be a novice in frac design from our lack of experience, or because we do not understand how to use our experience in a new or different reservoir setting. In very recent years, we have witnessed many highly experienced "frac gurus" fail to understand how to apply their experience when moving to horizontal wellbore applications. This paper will offer guidance to the less experienced frac design personnel as to some of the more important basic concepts of integrating hydraulic fracturing applications to reservoirs or well completion plans where little experience currently exists. Some reservoirs have been evaluated and reported in our literature to near "overkill" proportions for vertical completions and then struggled to understand frac stimulation of horizontal completions. Within the large body of technical papers and texts, most have slighted the importance of two factors: Rock hardness and formation pore pressure of gas reservoirs. This paper will stress the importance of including these factors. With record high oil prices, and in some markets, good gas prices, we are seeing the extension of hydraulic fracturing to areas and reservoirs where little or no "frac" experience exists. Additionally, our need to fracture stimulate when our wellbore is significantly deviated is starting to multiply in number and importance, both offshore and onshore. This paper will be a valuable aid to this transition.

AbstractIn 2004, SPE 90238, "Perforating and Hydraulic Proppant Fracturing in Western Siberia, Russia," provided recommendations for perforating in Western Siberia,1 an area where hydraulic fracturing is booming and considered second only to the North America region, with over 5,000 fracturing treatments performed each year. One of the issues that has become obvious over the past two years is the limited understanding of the importance of using well and reservoir data as major factors in the selection of perforating programs to prevent premature screenouts.In recent years, several operators have concluded that maximizing production from most wells in western Siberia fields requires the placement of large quantities of coarsesized proppant using the least damaging fluid systems possible in the fracturing applications. For production optimization, the proven trend is "larger (proppant sizes) and bigger (jobs)" using the lowest acceptable polymer loading in the frac fluids to minimize gel damage.To achieve successful placement of the designed optimized fracturing treatment, all factors that could lead to a premature screenout should be eliminated. Improper perforating practices have proven to be one of the primary limitations and are often proven as the number one reason for past screenouts. Using the preferred perforating guns and charges for a specific application reduced the total screen-out percentage to less than 5%. The key to proper selection of perforating methods included using API RP 19B data and simulation software that calculates downhole conditions.This paper describes several case histories in moderately hard and moderately soft rock reservoirs, using both big hole and deep penetrating guns, showing results that proved using proper perforating practices could eliminate screenouts. Furthermore, the authors describe how a different approach (hydrajet perforating) was used to provide entry from the wellbore to the formation. Hydrajetting will be compared with conventional (shape-charge) perforating techniques prior to hydraulic fracturing. Case histories for multi-zone pin-point stimulation will be provided.

Abstract In addition to rock permeability and reservoir pressure, variables important to the production of lateral wellbores have three major differences from those of vertical wells. These are (1) length of wellbore within the producing zone, (2) gravity effects, and (3) reservoir compartmentalization effects. If a horizontal wellbore will need hydraulic fracture stimulation a fourth variable, in-situ rock stress values and their directions, becomes a major factor: Historically, stress effects have been considered primarily for borehole stability concerns but become much more important to production potential if hydraulic fracturing is necessary for stimulation. Before the recent surge of horizontal drilling in ultratight gas reservoirs, only a small percentage of horizontal completions were known to be hydraulic fracturing candidates before drilling the well. Technology advancements have now significantly broadened the industry's ability to effectively place multiple fractures at preselected locations along a lateral section. In recent years, a large number of horizontals drilled in moderate to low-permeability oil and gas zones have proved only marginally economic; many were not economic when in layered reservoirs. For many of these wells, rapid production declines experienced on the "non-candidates" caused them to become stimulation candidates; and only then did the operator realize that many were drilled into a direction that decreased the opportunities for effective stimulation. Many horizontal wells will eventually need stimulation, even if not at initial completion. Identifying the type of the needed stimulation must be considered before the drilling and completion of the well. When lateral lengths were typically only a few hundred feet there was a higher probability that the formation in-situ stress condition would be essentially constant. As laterals are more commonly being extended thousands of feet, quite often they may be drilled through multiple fault blocks where the stress field can drastically change from one section of the lateral to another. When this occurs, a need to effectively fracture stimulate can result in significant changes to the way a fracturing placement program is implemented at specific locations along the lateral. The desire to "stimulate with the bit" has multiplied the number of multilaterals being drilled; if poor production forces an operator to consider fracture stimulation, this can further emphasize the importance of stress direction vs. lateral direction. This paper is intended to aid understanding of the ways that lateral wellbore placement and completion plan can influence (improve or reduce) the effectiveness of hydraulic fracturing applications. There is specific emphasis on many of the field and reservoir aspects (such as formation geology and localized tectonics) which may influence proper placement for future applications of fracture stimulation. Some aspects relate to well placement and others to specifics of lateral section locations. In the final section we will also reference many recent new techniques being applied to control fracture placements along laterals. Discussions include laterals that are completed as a barefoot open hole, with a non-cemented liner (pre-perforated or solid), or as cemented liner completions.

Summary Cased cemented completions have not been the preferred horizon-tal-well completion method in offshore Brazil. Lower-cost solutions such as uncemented preperforated liners were often used in completing horizontal wells offshore and are usually very effective. Often, however, low production rates mean that stimulation treatments become necessary for many wells. The use of conventional stimulation technology has generally been ineffective for these completions, which posed a challenge for the operator to find an effective solution for continuing developments in some fields. These challenges included reevaluating the more expensive cased cemented completions to allow more effective options for future stimulation, as well as trying to find newer stimulation techniques that can be effective with lower-cost completions (noncemented liners). In the attempt to find an economical yet effective stimulation solution, the operator chose to implement a unique and relatively new hydrajet stimulation technique that has a proven success rate in onshore applications. The technique can be applied in either sandstone or carbonate formations, which are commonplace in this field; therefore, stimulation plans in this area will include fracture acidizing as well as propped fracture stimulations that use a high concentration of proppants or curable resin-coated prop-pants (RCPs). This paper discusses the early results of this investigation. Wells that were completed and evaluated using different completion schemes are reviewed.

Abstract The application of horizontal completions in lower-permeability formations is continuing to proliferate on a global scale. Caused either by formation damage issues or the very heterogeneous nature of many such reservoirs, actual wells will underperform when compared to original predictions from reservoir simulations. This will continue to result in a need for effective hydraulic-fracturing stimulations for many of these wells to reach economic production levels. Horizontal completions in moderate- to low-permeability reservoirs present the challenge of cost constraints that seldom allow the use of long-proven methods such as cemented completions and individual-fracturing of numerous zones with bridge plug isolation and multiple perforating runs. Some new methods being applied to overcome this problem require expensive downhole "jewelry" and some added risks that the liner and jewelry can be entirely run to the predetermined depth. In some methods, the operator must also accept reduced completion IDs that can later restrict production rates or hinder workover operations. These increased costs and risks must be accepted even before the actual fracturing treatments are attempted. This paper will discuss a new approach to controlled placement of multiple-stage fracturing treatments without the risks involved with packers or bridge plugs. By implementing a coiled tubing (CT) deployed hydrajet-perforating method, immediately followed by a fracturing treatment pumped down the annulus, the operator can use lower cost (and lower risk) liner completions, and delay the decision of selecting exactly where the perforated sections should be placed. In many cases, the final decisions on placement of the next perforated location can even be delayed until after the wellbore displacement of the preceding fracturing stage. By pumping the fracturing fluid slurry down the annulus of the CT and the casing the allowable frac rates can be higher than with tubing-deployed techniques. The total stimulation related costs are greatly reduced by being able to perforate/frac multiple times within the same day. Even where more than one day is required to complete the stimulation of all desired locations along the lateral, only one CT intervention and one pumping service company mobilization and rig-up will be needed, which will still improve the job economy over conventional methods. An additional benefit includes a reduction in the potential for excessive multiple fractures or near-wellbore tortuosity encountered with explosive charge perforating.

Record high prices for oil and gas have increased the opportunity for producers to maximize the value of their assets. Under current market conditions, reservoirs previously considered marginal or even noneconomic can yield an acceptable return on investment and are increasingly considered for well completion. Many are lower-permeability formations that require fracture stimulation during the completion phase to deliver economic rates. In the latter part of 2004, a new stimulation technique was introduced to the industry, providing well operators a method to achieve multiple-zone fracture stimulation while controlling stimulation costs. By mid-2005, this new process had been evaluated by several operators in the US as well as Canada and Australia with very positive results.This new process offers the opportunity to perforate and stimulate multiple pay zones with a single well intervention, often within a single day. The technique employs a hydraulic jetting assembly on coiled tubing (CT) to erode perforations, immediately followed by pumping a fracture-stimulation treatment through the annulus between CT and casing. At the completion of the first fracturing stage, small-volume, high-proppant-concentration slurry is left in the wellbore to provide isolation of the just-stimulated zone from subsequent targets. In some applications, a wellbore screenout may also be induced to improve the temporary isolation of this zone. This sequence (perforate, stimulate, isolate) is repeated until all desired zones have been treated. Following the final stimulation stage, the well is cleaned out with CT and turned over to production. If needed, N2 gas can be pumped through the CT to kick-off the return flow.This paper describes the operational aspects, advantages, and limitations of using this new multistage perforating and fracturing technique with example field applications.

Abstract Currently, thousands of wells are being drilled every year in low- to moderate- permeability sandstone and carbonate reservoirs that have many distinct zones or layers that can contribute to production if adequately stimulated. In lower-permeability reservoirs, and especially for CBM completions, well economics will limit how much can be spent on the stimulation portion of a completion program. Operators may have to execute a "balancing act" with the need to maximize return on investment (ROI) while trying to complete as many contributing zones as possible. This usually drives a well operator toward methods that can minimize the number of separate well interventions while maximizing the number of zones that can be effectively stimulated. This paper provides a State of the Art review on both old and newer completion/stimulation techniques that can help an operator accomplish production goals. When the fracturing treatments are pumped down the casing, different methods applied can vary from simple, single-stage fracturing treatments using "limited entry" perforating to multi-stage fracture treatments with bridge plugs (BP) or ball/baffle stage isolation. Additionally, there are various other techniques incorporating conventional tubing strings with or without packers or BP's, and even various methods for coiled-tubing (CT)-deployed treatments. A "scorecard" approach presented here may offer operators an improved understanding of when a certain completion method is appropriate or flawed, based on the operators’ current understanding of specific reservoir characteristics of their field or well. Too often, a multilayer completion technique has been applied to several wells and later found to be a poor choice. The wrong choice may have been made because of a limited understanding of the completion method, or even of the reservoir itself. Often, an operator understands the variances of the reservoir, but does not realize the limitations that these variances should bring to the process of choosing the optimal simulation/completion method. In some cases, the choice has simply been made to take the low-cost completion/stimulation approach, and the resulting well(s) did not produce at (or sustain) economic levels.

Abstract Hydrajet fracturing, a relatively new stimulation technology for horizontal completions, has already proven successful in oil and gas wells across three continents. This multistage fracture stimulation method has primarily used jointed pipe to achieve hydraulic fracturing injection rates. The recent introduction of large OD coiled-tubing (CT) to the process has improved operating flexibility, reduced job time, and significantly enhanced health, safety, and environmental (HSE) performance. For some operations, it can also provide cost savings. Before 2003, most CT-conveyed applications of this process typically were limited to hydrajet-assisted acid-squeeze injections, with only a few low-rate acid-frac treatments performed. By using larger-OD coiled tubing, operators have placed propped fracture treatments to approximately 8,000 ft measured depth (MD) at treating rates up to 10 bbl/min. The use of a combined workstring consisting of jointed pipe connected to a surface string of CT can enable these multi-stage treatments to be placed in much deeper reservoirs, effectively doubling or tripling the depth capability of a CT-deployed treatment. For many applications this capability would provide the flexibility, speed, and safety inherent to coiled-tubing operations with a spool of only a few thousand feet, and jointed pipe would not be exposed to high treating pressures at the surface. This paper reviews several field applications where coiled tubing was used to deploy hydraulic jet fracture treatments. One field case is compared directly to an earlier treatment in the same reservoir, which had been pumped through jointed pipe.