When a new well is being fractured, anyone with a producing well nearby needs to look out for hits.
The hydraulic pressure used to fracture a new well is likely to be felt in older wells nearby because fractures tend to grow toward zones where the pressure has been depleted by production.
“It is unrealistic to expect total avoidance in formations such as the Eagle Ford, Woodford, and Bone Springs,” said Mike Rainbolt, completions engineer, senior advisor for Apache Corp., adding “let me rephrase that—it is impossible.”
The risk of a hit is high in those plays in Texas and Oklahoma because hydraulic fracturing there is likely to create long planar fractures, whose growth can be magnified by aggressive fracturing designs used to maximize liquids production.
Damage caused by “frac hits” is the high-profile problem that has fanned interest in the larger, but less obvious issue of how fracturing affects the reservoir between tightly spaced wells. Rainbolt presented a 43-page paper by Apache (SPE 187192) at the 2017 SPE Annual Technical Conference and Exhibition in October, which offered a broad look at the problem with examples and ideas on how to manage it.
The impact of a hit can be big and immediate. The Apache paper included a look at a well whose production dropped 65% after a hit and remained down until it was treated.
But these fracturing-driven interactions may only be apparent with production analysis. Apache’s study found one pair of wells where the area fractured by the second well overlapped with the original well. As a result, it said “the existing well could have produced the reserves without the infill well.”
Tightly spaced wells fractured using more water and sand are producing more oil, “but if you look at the incremental production per frac, you see it is going down,” said George King, the lead author on the paper and the global technology distinguished engineering advisor for Apache.
King is leading an effort with Ali Daneshy, president of Daneshy Consultants International, to produce an SPE technical paper commissioned by the SPE Board of Directors on fracturing-driven interactions due in the spring.
What was once old is now new again in US natural gas production. Once a crown jewel of shale in the US, the Haynesville has seen a resurgence in activity after a steady drop. Now, as natural gas consumption increases and the oil price remains low, companies are taking advantage of a potentially valuable opportunity in the area.
Located in east Texas and northern Louisiana (Fig. 1) the Haynesville was the largest US producer of shale gas. In November 2011, it averaged a record high production of 10.4 Bcf/D—but as natural gas prices decreased in the years leading to the oil price downturn, other plays in the Appalachian region of the US such as the Marcellus and the Utica began to surpass it in production. By 2015, shale gas production in relatively liquids-rich areas such as the Eagle Ford and the Permian were also producing more than the Haynesville.
The demise of the Haynesville appeared to be short-lived, though. In the past 18 months, the US Energy Information Administration (EIA) noted significant increases in drilling activity and well production rates, which have raised overall natural gas production in the region. Natural gas production reached 6.9 Bcf/D in September after remaining near 6.0 Bcf/D on average for the past 3 years.
Beyond the Numbers
Fig. 2 highlights some of the trends in the Haynesville. The EIA projected natural gas production to increase by 146 MMcf/D from October to November 2017. Rig count has nearly doubled from 2015 to the end of 2017.
A drop in well costs has helped drive the surge in activity. In 2014, the Haynesville had the most expensive costs in the US primarily because of the challenges its fuel-bearing rocks presented. The formations were among the deepest in the country, with some as deep as 15,000 ft. In the Appalachian region, wells are in areas where formations range from 2,000- to 12,000-ft depth. The shale formation thickness in the Haynesville is slightly narrower than other US shale plays as well, ranging from 100 to 350 ft.
In addition, the high pressure and temperature conditions led to stimulation treatments consisting of high-strength proppant and more thermally stable fluids. These fluids consisted of large polymer loadings of guar and sometimes derivatized guar gelling agents. Higher-quality resin-coated and ceramic prop-pants were commonly pumped as the primary proppant, increasing costs and forcing companies to adopt a strategy of “quality over quantity” in terms of production volumes (SPE 187315).
Understanding and prioritizing water management is key for exploration-and-production operators, not only in terms of reducing overall cost and capital expenditures but also as a means of mitigating operational risk, complying with changing regulatory requirements, and addressing environmental concerns. Water-management decisions within shale oil and gas production fall into three primary categories: water acquisition, water usage within hydraulic-fracturing operations, and the disposal of produced and flowback waters from drilling and production. Shale-fracturing flowback refers to the portion of injected hydraulic-fracturing fluids that returns to the surface before and during initial production. The large quantities of flowback and formation water generated during the fracturing process must be treated before recycling, beneficial reuse, or disposal. Typically, 10–20% returns within 7–14 days, with a rapid decline in quality and quantity. Shale produced water typically refers to water produced during the production phase of the shale wells in the longer term and has significantly lower flow rates and more-consistent quality than flowback water. The characteristics of produced and flowback water vary, but both types of water must be treated properly and disposed of correctly or recycled.
Numerous technologies are available today to enable complete or tailored removal of ionic, organic, and particulate contaminants from source waters for injection or produced waters for discharge.
From fine-particle filtration to remove suspended solids and selective-ion exchange for boron removal to polymeric adsorbents for organic-compound removal, numerous water-management solutions are available to ensure that flowback water and produced water are treated properly for recycling, reuse, or disposal.
The papers featured in this month deal with water management in south Argentina, a salt-tolerant friction reducer, and a novel water-shutoff system for carbonates. I hope you enjoy reading the selected papers.
Recommended additional reading at OnePetro: www.onepetro.org.
IPTC 18936 Integrated-Water-Management Challenges by H. Al-Shammari, Kuwait Oil Company, et al.
SPE 183340 Innovative Approach To Treat Produced Water for Reuse in Saudi Aramco Reservoirs Pressure Maintenance by Mohamed Ahmed Soliman, Saudi Aramco, et al.
SPE 183743 Maintaining Injectivity of Disposal Wells: From Water Quality to Formation Permeability by Ali A. Al-Taq, Saudi Aramco, et al.
SPE 184520 On-Demand Water Control: Molecular Host/Guest Interaction for In-Situ Modification of Formation-Fluid Permeability by Antonio Recio III, Halliburton, et al.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184052, “Case Study: A New Salt-Tolerant Friction-Reducer System Enables 100% Reuse of Produced Water in the Marcellus Shale,” by Liang Xu, SPE, Multi-Chem, a Halliburton Service; Paul Lord, Halliburton; Justin Koons and Todd Wauters, SPE, Multi-Chem, a Halliburton Service; and Sam Weiman, EQT, prepared for the 2016 SPE Eastern Regional Meeting, Canton, Ohio, USA, 13–15 September. The paper has not been peer reviewed.
To continue to treat multiple clusters in longer laterals effectively, even for stages near the toe, a robust friction-reducer (FR) system typically is required to overcome pipe friction. Additionally, using a single FR system throughout the entire treatment that can tolerate various water sources of varying salinity up to 300,000 ppm is imperative. This paper discusses the field trials of a new salt-tolerant FR system in the Marcellus Shale.
FRs are used to enable high-rate pumping of water while maintaining lower treating pressures in both slick water fracturing and coiled-tubing stimulation applications. Typically, the performance of conventional acrylamide/acrylic acid copolymer or partially hydrolyzed polyacrylamide-based FRs diminishes as the dissolved-ion content of the source water increases and can be dependent on both the type and the concentration of ions present in the source water. Because of this limitation, flow-back and produced water used for slick-water applications are often diluted with a freshwater source to maintain adequate friction-reducing performance. To enable the use of 100% produced water, new friction reducers have been developed that are capable of providing near-freshwater performance in flowback and produced water exceeding 300,000 ppm total dissolved solids (TDS).
The new salt-tolerant FR consists of FR systems that are designed to work in a specific range of high salinity to enable the use of 100% flowback and produced water in slickwater hydraulic- fracturing applications without requiring dilution with fresh water. The salt-tolerant FR service can handle TDS levels greater than 300,000 ppm; is effective in water containing a variety of dissolved salt ions, including chlorides, sulfates, sodium, calcium, and magnesium; and can tolerate a variety of unknown contaminants that might render conventional FRs ineffective. The new FR system is effective at low concentrations (0.25 to 1 gal/1,000 gal) in clay-control brines and flowback and produced-water sources.
This new salt-tolerant FR system consists of a water-in-oil cationic polymer and an inverter. Unlike other FRs, the distinctive advantage of the new FR is that the ratio of polymer to inverter can be readily adjusted on the fly to achieve maximum friction reduction. During the pumping operations, it was demonstrated that the inverter was sufficiently quick to invert and release the polymer from oil to water and the cationic polymer was extremely efficient at reducing additional pipe friction, even with severely impaired water. Additionally, the use of a single FR reduces inventory stock and simplifies on-location quality assurance of material usage.
In offshore steel structures engineers often face the problem of assessing the criticality of existing hot spots to predict the remaining lifetime and thus to develop sound reliability-based inspection programs. One problem with such an approach is that the past fatigue conditions cannot be appropriately modeled, and the degree to which damage has accumulated in hot spot areas cannot be consistently modeled. This paper shows a practical methodology for predicting the remaining fatigue life of hot spots by using a probabilistic fracture mechanics approach and shows how in general the results can be used in reliability-based inspection programs.
At present, the best practice for modeling remaining fatigue life and identifying hot spots in existing offshore steel structures is the traditional S–N approach (Miner’s rule). The uncertainties in the S–N approach for existing structures are significant, and it is often impossible to take into account the stress cycles to which the structure has been subjected in the past, especially in cases where the structure has been strengthened or modified. This results often in very low fatigue life, sometimes even lower than the actual age of the structure. The S–N approach has thus only limited use for identifying measures and for establishing risk- and reliability-based inspection plans for such hot spots in existing structures.
The present paper shows how a probabilistic fracture mechanics approach can be used to analyze the existing hot spots in an offshore steel structure and how reliability-based inspection planning can be established based on these results. The general approach is to postulate cracks of specific length and depth that match the threshold of known inspection techniques, to have cracks located in specific directions at the hot spot locations, and then to predict the crack growth and failure probability of the postulated cracks.
Openhole (OH) multistage fracturing (MSF) is increasingly used to stimulate and maximize production within low-permeability reservoirs in unconventional plays globally, extending its use from tight sands, shales, and carbonate reservoirs. Technological breakthroughs in hydraulic fracturing have helped enable OH MSF within lateral sections.
The target reservoir is a tight heterogeneous carbonate with unsustainable productivity. The hydrocarbon produced is oil of relatively low API and gas/oil ratio (GOR). Given the challenging nature of the unconventional Mauddud reservoir of the Bahrah field, a sophisticated design of both the well completion and fracturing treatment is necessary to achieve the North Kuwait strategic production targets by maximizing reservoir contact and enhancingwell performance.
A long horizontal well was drilled within the Mauddud reservoir. Completion technology was based on distributing swellable packers along the lateral section to develop MSF acidizing.
The multistage packer and port designs were based on the reservoir mechanical and formation properties, to achievethe best fracture extension. Fracture acidizingwas performed on each stage, the well was flowed clean, and an electrical submersible pump (ESP) was run to produce the well. A production logging tool (PLT) survey was run immediately after fracture acidizing and six months after production. The recorded data indicated different contribution profiles of the stages, which indicated the fractures and production within such reservoirstake time to stabilize.
This paper describes and addresses the effectiveness of MSF. Additionally, MSF performance in horizontal vs. vertical wells is assessed. Well performance analysis, exploitation approaches, and successful implementation are discussed, highlighting the advanced completion technology applied. The PLT results at different stages of the well life (post-acidizing and after ESP installation) are discussed. A comparison between the multifracture within the lateral section and vertical fractured well showed the benefit of the technology used to boost and sustain production. Effective horizontal drilling and MSF have helped enablethe development of unconventional resources, which were considered economically unfeasible previously.
The Campos basin is a sedimentary basin located in offshore Brazil, between the north coast of Rio de Janeiro State and the south coast of Espírito Santo State, encompassing many oilfields. Most of the reservoirs in the basin are high-permeability sandstones containing low API gravity oil but are without strong water drives. Long horizontal producer wells are the best economic option for field development but require water injection to maintain reservoir pressure. Horizontal sections generally range from 1000 to 2000m, which demands gravel pack as a sand control method. Gravel packing such long wells is a challenge and requires thoughtful engineering to optimize pumping techniques and technology. Presented here are best practices to overcome several challenges faced in this field to achieve overall success.
The challenge for extended-reach gravel packing is that the long horizontal section develops high friction during the alpha and beta wave propagation. Increasing the pumping pressure to overcome this friction increases the risk of fracturing the formation, consequently reducing the equivalent circulation rate downhole impairing the proppant transportation. In contrast, a reduced pump rate during alpha wave propagation can lead to a premature screenout due to the increase in dune height of over 85%. To overcome these issues and place gravel packs in these wells, careful engineering and simulation, lightweight proppants, friction reducers, and thorough job planning were used to successfully perform gravel packs in more than 40 horizontal wells completed in the Campos basin from 2011 up to 2017.
The experience of pumping the longest gravel pack jobs in offshore Brazil (horizontal length more than 2,000m) offer insights into best practices for gravel packs in extended-reach horizontal wells: Design considerations, specific well challenges faced, technologies deployed, and operational planning requirements. Specifically, highlighting the benefits of using lightweight proppants and optimized fluid systems to minimize screen out risks and maximize pack efficiency.
Gas-bearing carbonate reservoirs in moderate to low permeability reservoirs have been targets for acid fracturing treatments in the Middle East. These formations typically exhibit high temperatures, medium to low porosity, and high heterogeneity in terms of lithology and reservoir properties. The heterogeneity dictates completion strategy, with multiple perforated intervals across large gross height in vertical wells with subsequent acid fracturing treatments that aim to cover all perforated intervals in a single treatment. But due to differences in lithology, intervals with high dolomite content are less likely to receive stimulation due to higher stress and reduced acid reactivity. Temperature logs performed on many wells after conventional acid fracturing treatments showed that these perforated intervals accept only a small amount of treating fluids, compared to intervals perforated in clean limestone. An efficient, non-damaging, near-wellbore diverter is required to efficient treat all intervals and improve productivity in such wells.
The objective is to stimulate all existed intervals in a single pumping operation, regardless of reservoir heterogeneity, by using degradable diverting materials to temporarily isolate created fractures and redirect the flow to untreated areas. The diversion material used is a composite pill comprising a proprietary blend of degradable fibers and multimodal particles, designed to provide an effective isolation plug at the face of the reservoir in a consistent manner. Fibers are added to ensure the integrity of the diversion pills during delivery and to enhance the bridging mechanism. The use of fibers allows minimizing required diverter volume to few barrels and engineered multimodal diverting materials allow having very strong diversion pressure with small amount of the material. The process increases operational efficiency, well productivity, and estimated ultimate recovery. The materials used to provide temporary isolation have proprietary formulation that degrades within hours or days, depending on bottomhole temperature, with no need of intervention or pumping chemicals to break down the system.
Two pilot treatments with degradable diverter were conducted in high temperature high pressure carbonate reservoirs. Extensive measures were undertaken to evaluate the treatments, including pressure analysis, separator tests, temperature logs, production log (PLT), pressure build up (PBU), and nodal analysis. Overall, the measurents and analysis of the treatments proved the efficiency of the degradable diverter for vertical wells: sharp pressure increase up to 1,600 psi when pills arrived at perforation; cooldown effects in all intervals on the post-fracturing temperature logs ensuring uniform distribution of the acid; high flowback gas rates, substantially higher than those of offset wells treated without the diverter; fracture response and signature observed on PBU data; PLT contribution from most of the perforated intervals confirming that treatments penetrated all intervals of interest; and nodal analysis with good production match showed long etched fracture half-length - a preferred fracture geometry for tight reservoirs.
Understanding the created fracture geometry is key to the effectiveness of any stimulation program, as fracture surface area directly impacts production performance. Microseismic monitoring of hydraulic stimulations can provide in real-time extensive diagnostic information on fracture development and geometry. Thus, it can help with the immediate needs of optimizing the stimulation program for production performance and long-term concerns associated to field development. However, microseismic monitoring is often underutilized at the expense of productivity in the exploration and appraisal phases of a field.
Geology is a fundamental element in the design of a stimulation program and the interpretation of its results. Rock properties and geomechanics govern the achievable fracture geometry and influence the type of fluids to be injected in the formation and the pumping schedule. Rock layering controls the location of the monitoring device, guides the depth at which perforations should be located, and influences how hydrocarbons flow within the formation. Despite this importance, the impact geology may have on the stimulation results is often overlooked as it is all too common to see assumed laterally homogeneous formations, invariant stress field (both laterally and vertically), stimulated fractures having a symmetric planar geometry, etc.
As exploration and appraisal moves toward active tectonics areas (as opposed to relatively quiet passive margins and depositional basins), understanding the impact of complex geology and the stress field on fracture geometry is critical to optimizing stimulation treatments and establishing robust field development plans. Mapping of hypocenters detected using microseismic monitoring is an ideal tool to help understand near- and far-field fracture geometry. Additionally, moment tensor inversion performed on mapped hypocenters can contribute to understanding the rock failure mechanisms and help with evaluating asymmetric and complex fracture geometry. Understanding this fracture complexity helps address key uncertainties such as achievable fracture coverage of the reservoir.
We present the results of several hydraulic fracture stimulations in various geological environments that have been monitored using microseismic data. We illustrate with these case studies that in some rare cases, simple radial and planar fracture system (often mislabeled penny shape-like fracture) may be generated as predicted using simple modeling techniques. However, in most cases, the final fracture system geometry is complex and asymmetric, largely governed by stress, geologic discontinuities, rock fabric, etc. Understanding this impact and optimizing the well design to enhance productivity is key to evaluating reservoir potential and commercial viability during exploration and appraisal phases and for maximizing return on investment during development.
Challenges have arisen when developing a relatively tight oil reservoir in Saudi Arabia using conventional matrix stimulation techniques to improve well productivity. The oil producer wells responsiveness to matrix stimulation was not adequate to supply the estimated oil production capacity due to the tightness carbonate reservoir formation. In order to get better well productivity in this low permeability environment, open hole with multistage frac completion using swellable isolation packers was chosen to develop this reservoir.
This paper discusses the challenge journey of first ten multistage job from the well drilling and completion stage, design and lab optimization of the fracturing fluids, modeling of the optimized fracture geometry, onsite well QA/QC of each stage fracturing fluids. In addition, step rates test regression approach prior each stage for fracturing gradient calculation, pre and post fracturing injectivity test, and finally analyzing the flowback samples for four days.
A ten multistage acid fracturing was performed on an oil producer well that was drilled as a single lateral into the oil tight carbonate reservoir. The well was completed with a ten sleeve multistage fracturing and eleven oil swellable packers. These packers showed excellent zonal isolation with no communication observed during the fracturing operation. The job resulted in a well producing 9 folds of production, with a water cut range less than 10 %. The four days flowback samples analysis revealed the need for longer cleaning up time.
A successful approach was achieved using multistage acid fracturing technique. Lessons learned from this job planning and execution shed the importance of previously steps for future acid fracturing jobs in similar oil fields.