With an active drilling program that was generating over 90,000 barrels of drilling waste each year, the THUMS Long Beach Unit in Wilmington Field, California, was spending over 3.5 million dollars per year to dewater and ship these solid wastes to on-shore landfills for disposal. In 1994, THUMS implemented an environmentally safe and economic program of hydraulic fracturing for the long-term, onsite disposal of drilling mud, drill cuttings, and tank bottoms. By reinjecting the drill cuttings downhole, transportation, the major portion of drilling waste disposal costs, was eliminated. This paper reviews the regulatory permitting process and addresses injection interval assessment, well candidate selection, fracture containment, and offset well seismic monitoring. The equipment, injection history, and economics of disposing over one million barrels of slurry over a 3-yr period are detailed.

A frac-pack technique combines the stimulation advantages of a highly conductive hydraunc fracture with the sand control of a gravel pack to improve productivity in low to moderate permeability, unconsolidated formations. This paper presents the results of two offshore field tests in the Gulf of Mexico which evaluate different fracturing fluids, unconventional proppant sizes and new gravel packing tools. Aspects of reservoir candidate selection, pre-and post-frac pressure testing, and production results are addressed. This paper examines the layout of equipment, fracture treatment design, and on-site fracture optimization through minifrac testing.The first field test explores the use of platform mounted gravel pack tanks with batch mixed sand slurries in a linear hydroxypropyl guar (HPG) gel that is crosslinked with Borate on the fly. The second field test investigates the use of linear hydroxyethylcellulose (HEC) gel as a fracturing fluid with a conventional blender and gravity feed proppant silo on a stimulation boat moored along side the production platform. These field tests demonstrate a frac-pack technique can provide practical and cost effective fracture stimulation and sand control in the offshore environment.

Summary It has been assumed that along with fluid viscosity and pump rate, gravity dominates final proppant placement in hydraulic fractures. Results here, based on detailed multiphase-flow modeling, show that other factors such as slurry rheology (effect of adding proppant on slurry viscosity), fluid loss and layered fluid loss, and vertical fracture-width variations often are more important than gravity in controlling placement. Abstract The goal of a hydraulic-fracture treatment is to create a large flow area exposed to the formation and connected to the wellbore along a conductive path. The only goal of hydraulic-fracture models is to predict this final proppant placement accurately. Most theoretical, modeling, and experimental efforts in this area have focused historically on understanding and predicting only gravity effects on proppant placement. However, for proppant-laden, viscous fluid or slurry flowing along a fracture, other forces are always more important than gravity, and can easily cause proppant to move upwards, both during pumping and fracture closure.A differential-fracture closure occurs when a fracture growing vertically penetrates zones with higher or lower closure stress. After shut-in, higher stress zones "close first." This forces any proppant-laden slurry covering these zones (at shut-in) to migrate to low stress zones where fracture width is greater, and can easily lead to "upward" proppant movement as fracture-closure stress generally decreases with depth.After shut-in of a propped fracture treatment all fluid must leak off into permeable formations penetrated by the fracture. Until closure, viscous fluid continues to transport proppant (possibly upward) toward fluid-loss layers, often corresponding to "pay."As proppant is introduced to fluid, the resulting slurry has a higher density and tries to move downward. However, solids also act to increase viscosity, and more viscous slurry prefers the wide middle of a fracture. This serves to keep proppant near the middle of the fracture, often in the pay zone. This paper discusses the combined effect of these forces on proppant placement in a context of post-frac analysis of several field treatments. Analysis used a fracture model including "rigorous," numerical, 2D material transport, and the often-unexpected results are compared with supporting evidence from post-frac well performance. In many instances, the combined effect of proppant-placement forces is beneficial, with more proppant placed across the pay than suggested by simple models. In other cases, post-shut-in proppant redistribution can (and did) cause catastrophic job failure. Introduction The goals of a hydraulic-fracture treatment are to increase the flow area exposed to the formation, and then to connect that flow area to the wellbore via a high-permeability path. For propped-fracture treatments, placing a proppant in the fracture creates this conductive path. The quality of proppant is designed to maintain lasting, high permeability under conditions of in-situ stress, temperature, etc. Because the only goal of field operations is to place this permeable proppant in the desired location, results from numerical design and analysis models must represent proppant transport in the fracture accurately. Proppant transport has received its share of attention along with the required analysis/design steps of understanding and predicting fracture geometry and fluid loss. This led immediately to studying effects of gravity on proppant placement. As anyone falling off a ladder can attest, gravity is a major natural force. Because the oil industry normally deals with near-vertical fractures, the influence of gravity on proppant placement and proppant settling is clearly a major concern. Kern et al.1 conducted laboratory experiments to determine a "critical" velocity where no additional sand dune formation would occur. This was followed by important work by Novotny,2 Clark and Quadir,3 and others. These works concentrated on single particle or "Stoke's law"-type proppant settling. Stoke's law can be stated asEquation 1 where the equation in this form must use consistent units. The actual phenomenon is more complex, of course, and final proppant placement is a function of pump rate and the effects of proppant concentration on slurry viscosity and thus on settling rates. In its simple form, however, this still shows settling as a combined function of gravity and viscosity. More recently, it was understood that proppant-laden slurry was denser than the "clean" fluid pad pumped to open a fracture. This heavier slurry tends to sink and tries to under-run the lighter pad fluid. This was probably first discussed (in terms of 3D fracture modeling) by Clifton and Wang.4 This behavior has been proposed as a major influence on proppant placement.5,6 Clark and Zhu7 proposed a dimensionless constant which uses consistent units, written asEquation 2 where values <1 would indicate a strong possibility for convection, while for values >1 lateral flow would dominate and convection-type settling would be minimal. If confirmed, this could prove a valuable tool for modeling, particularly for cases where a rigorous fluid-flow, proppant-transport solution is not used. While Nc is valuable as a screening tool, results and comparisons suggest the problem is more complex than suggested by this dimensionless constant. The additional complexity arises because of variations in fracture width over the fracture height, and effects of proppant on slurry rheology.

While over six hundred Kuparuk A Sand wells have been hydraulically fractured or re-fractured successfully from deviated wellbores, a number of wells in the field have not responded to the conventional fracture treatments. In these wells, the conventional design resulted in premature, near"wellbore screenouts, with low proppant placement, and consequently, poor productivity, A symptom common to each of the failed treatments was a near-wellbore friction pressure loss too high to be explained by perforation restriction or simple fracture twisting and turning. An extensive analytical study of hydraulic fracture initiation and propagation from deviated wellbores suggested multiple fractures as a mechanism to account for the abnormally high nearwell bore friction pressure loss and the reduction in fracture width. A model was developed (XFRAC) which correlates these responses to formation stress, wellbore parameters and treatment conditions. A counter-intuitive fracture treatment which employed lower pumping rates combined with higher viscosity fracturing fluids was designed to minimize the formation of multiple fractures and increase fracture width. This unconventional design has been successfully pumped in eleven wells which exhibited the premature screenout problem. Proppant placement was increased over ten fold with a tripling of post-frac production rates and a 35 percent increase in estimated recovery.

This paper describes the implementation of an environmentally safe and economic program of hydraulic fracturing for the long term disposal of tank bottoms, drilling mud and drill cuttings for the THUMS Long Beach Unit in Wilmington Field, California. Each year THUMS' active drilling program generates over 90,000 barrels of drilling waste costing the Long Beach Unit approximately 3.5 million dollars to de-water and ship to landfills for disposal. By re-injecting the drill cuttings downhole, transportation. the major portion of drilling waste disposal costs, can be eliminated. This paper reviews the permitting process with local regulatory agencies, describes the engineering aspects of injection interval and well candidate selection and addresses the issues of fracture containment and offset well seismic monitoring. The equipment, injection history and economics of disposing over 450,000 barrels of slurry and 12,600 cubic yards of solid materials over a two year period is also detailed. Introduction The Wilmington Field, discovered in 1936, is the largest field in the Los Angeles Basin and the fourth largest oil field in the United States having produced over 2 billion of the estimated 3.1 billion bbls of oil originally in place. The Long Beach Unit (LBU) with 900 million bbls of oil in place covers 6479 acres of the eastern portion of the field (Figure 1 - Geologic Setting of Long Beach Unit) underlying the downtown area of the City of Long Beach and the recreational offshore harbor area. Although production began in the western portion of Wilmington Field in the late 1930's, concern for surface-subsidence left the eastern portion of the field, including the LBU, undeveloped until the early 1960's when legislative and legal actions cleared the way for development under highly controlled conditions designed to protect the environment. The LBU is operated by the City of Long Beach (City) through its Department of Oil Properties with the California State Lands Commission (State) approving the plan of operations and budget, the bottomhole location of all new wells and other specific well details. As a result of competitive bidding, THUMS Long Beach Company (THUMS), originally a consortium of five major oil companies, Texaco, Humble (Exxon), Unocal, Mobile and Shell, became field contractor for the Unit. Since production began at the LBU in 1965, over 1300 wells, a quarter of those injection wells, have been directionally drilled from four man-made gravel islands and a land filled pier located in the Port of Long Beach. By the end of 1991, each of the five original THUMS stockholders had sold their shares to ARCO Long Beach Inc. (ALBI), a subsidiary of Atlantic Richfield Company (ARCO). In 1992, ARCO began the investment of more than $100 million in a new enhanced waterflood project for the Unit. THUMS' active drilling program was generating over 90,000 barrels of drilling waste per year. At that time, drilling wastes were being de-watered and shipped by truck to permitted landfills for disposal at a cost of over $3.5 million annually. By 1993, concerns over increasing cost and the availability of landfills to meet disposal requirements led THUMS to investigate alternative methods of waste disposal. ARCO and others were already employing on-site disposal of drill cuttings and other solid wastes in remote onshore areas such as the North Slope and in offshore operations in the Gulf of Mexico, North Sea, and Mediterranean. The success of these waste disposal efforts led THUMS to initiate their own program of hydraulic fracturing for the long term disposal of slurrified non-hazardous drilling wastes. P. 77^