Wilmington Field Research Articles

Empirical Evidence Demonstrating Injection Containment and Absence of Injection-Induced Fracturing, Wilmington Oil Field Case Study

Summary Waterfloods in California operate under the US Environmental Protection Agency's Class II underground injection control regulations, which are tasked with the protection of underground sources of drinking water (USDW) within the state. A key aspect of this regulatory framework is the operation of water injection wells under a maximum allowable surface pressure (MASP) to ensure that injected water does not induce and/or extend formation fractures that could create a potential conduit connecting the hydrocarbon zone with identified USDWs. Determination of the MASP for individual injection wells has typically been calculated using a step rate test (SRT), but this method has been shown to be inappropriate for multilayered, unconsolidated sandstone reservoirs (Ershaghi and Ershaghi 2018), which are prevalent in Wilmington Field. To avoid the potential for misinterpretation of SRTs to imply fracturing in this context, in this paper we summarize the evidence demonstrating both the effective geologic containment of injected fluid in the hydrocarbon-bearing zones and the absence of injection-induced fracturing. In addition, a series of field tests were conducted to assess the stress sensitivity of the Wilmington reservoirs and investigate in-situ changes in the reservoir at higher injection pressures by combining multirate injection tests with injection profile surveys. These results provide data supporting the noted challenges associated with MASP determination for multilayered, unconsolidated reservoirs. In this paper, we give operators and regulators working in these types of fields a framework for assessing both injection containment and injection-induced fracturing that account for the unique properties of these formations.

Paleochannel sands as conduits for hydrocarbon leakage across faults: An example from the Wilmington oil field, California

This article evaluates the impact of a submarine channel sand in the western Wilmington oil field, California, on hydrocarbon accumulation and leakage across boundary faults. The Wilmington field is in a broad anticline broken into 10 fault blocks by normal faults. The coarse-grained channel deposit, named T4, is identified in fault blocks I through III within the Tar zone, a lower Pliocene turbidite deposit and the shallowest productive zone in the area. The channel deposit incised into three sand units: T2, T5, and T7. Evidences of tilted oil-water contacts (OWC), OWC cutting structure depth contours, scattered oil traces, and fault seal analysis all indicate that the channel deposit is responsible for hydrocarbon leakage across the boundary faults. The leakage occurs in the three channel-incised sand units: T2, T5, and T7. In fault block I, hydrocarbons in the three sands charge the channel sand at the structural culmination, and then leak across the eastern boundary Wilmington fault into the wet S sand directly above the Tar zone on the hanging-wall block. In fault block IIA, hydrocarbons from the T5 and T7 sands pool in the channel sand on the north flank and leak across the eastern boundary Ford fault into the S sand on the hanging-wall block. This leakage across faults caused depletion of almost all hydrocarbon accumulations in the three channel-incised sands in fault block I. The leakage also raised OWCs on the north flank in fault block IIA, resulting in tilted OWCs in the two channel-incised sand intervals.

Predicting and monitoring long-term compaction in unconsolidated reservoir sands using a dual power law model

We propose a model for predicting the long-term creep compaction of unconsolidated sand reservoirs prior to significant depletion. The model is based upon linear viscoelasticity theory, whereby deformation is decoupled into instantaneous and time-dependent components. The instantaneous component of deformation is modeled using a power law function of effective pressure. Model parameters are solved by conducting a constant strain-rate laboratory experiment. The time-dependent deformation is modeled using a power law function of time. Associated model parameters are solved by conducting a creep-strain test at the anticipated in-situ effective pressure. In total, application of the model involves measurement of three model parameters obtained by conducting two different laboratory experiments. We illustrate the model utilizing samples from unconsolidated sand reservoirs in the Wilmington field in California and an offshore field in the Gulf of Mexico. We show that the stiffness change associated with the porosity reduction predicted by the model is large and could be monitored using P-wave velocity. This should make compaction observable with 4D seismic surveys of the example fields.

Viscous deformation of unconsolidated reservoir sands—Part 1: Time‐dependent deformation, frequency dispersion, and attenuation

Laboratory experiments on dry, unconsolidated reservoir sands from the Wilmington field, California, reveal significant viscous creep strain under a variety of loading conditions. In hydrostatic compression tests, following initial loading to 10 MPa, the creep strain that accompanies 5‐MPa loading steps to 15, 20, 25, and 30 MPa exceeds the magnitude of the instantaneous strain (∼3 × 10−3). We observed a two‐fold increase in bulk modulus with frequency over the range of frequencies tested (10−6to 10−2Hz), which is consistent with a viscoelastic rheology of unconsolidated sand. The data demonstrate that the effective static bulk modulus is approximately one‐third of that at seismic frequencies. By measuring the phase lag between stress and strain during the loading cycles, we were also able to show that inelastic attenuation is nearly constant (Q ≈ 5) over the four‐decade range of frequencies tested at a strain amplitude of 10−3. Interestingly, the viscous effects only appear when loading a sample beyond its preconsolidation. Triaxial tests show that the relationship between differential stress and axial strain is positively dependent on axial strain‐rate, and that unconsolidated sand continues to deform viscously even at large strains (∼7%). All experiments were conducted at room temperature and humidity. A limited number of experiments with unconsolidated reservoir sand from the Gulf of Mexico show similar behavior.

ABSTRACT: Increasing Reserves through Optimized Waterflooding: The Long Beach Unit, Wilmington Field, California

ABSTRACT: Increasing Reserves through Optimized Waterflooding: The Long Beach Unit, Wilmington Field, California

ABSTRACT: Identification of Undeveloped Reserves of the Ford Zone Sands in the Wilmington Townlot Unit, (WTU) Wilmington Field, Los Angeles County, California

ABSTRACT: Identification of Undeveloped Reserves of the Ford Zone Sands in the Wilmington Townlot Unit, (WTU) Wilmington Field, Los Angeles County, California

Gravel Packing Ultra Slim 1.9" Inner Liners in the Long Beach Unit, Wilmington Field

Gravel Packing Ultra Slim 1.9" Inner Liners in the Long Beach Unit, Wilmington Field

THUMS Long Beach Unit Subsea Pipeline Integrity Program, Wilmington Field

THUMS Long Beach Unit Subsea Pipeline Integrity Program, Wilmington Field

Statistical Analysis Leads to New Sand Control Guidelines in the Long Beach Unit, Wilmington Field

Statistical Analysis Leads to New Sand Control Guidelines in the Long Beach Unit, Wilmington Field

Extension of Well Life Through Inner Liner Technology, Rate and Reserve Impacts in the Long Beach Unit, Wilmington Field

Extension of Well Life Through Inner Liner Technology, Rate and Reserve Impacts in the Long Beach Unit, Wilmington Field

How Clean Should Our Water Be? Reservoir Engineering Perspective on Water Quality in the Long Beach Unit, Wilmington Field

How Clean Should Our Water Be? Reservoir Engineering Perspective on Water Quality in the Long Beach Unit, Wilmington Field

Ranger 8B Fault Block Reservoir Study and Development Drilling Results, Long Beach Unit, Wilmington Field

Ranger 8B Fault Block Reservoir Study and Development Drilling Results, Long Beach Unit, Wilmington Field

On-site Fracturing Disposal of Oilfield-Waste Solids in Wilmington Field, California

Summary 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.

New Acid System Minimizes Production Decline

This article is a synopsis of paper SPE 46201, "New Acid System Minimizes Post-Acid Stimulation Decline Rate in the Wilmington Field, Los Angeles County, California," by Gregory D. Dean, SPE, Chris A. Nelson, SPE, and Steven Metcalf, BJ Services Co. U.S.A., and Randy Harris, SPE, and Terry Barber, SPE, THUMS Long Beach Co., originally presented at the 1998 SPE Western Regional Meeting, Bakersfield, California, 10-13 May.

3D Modelling/Visualization Guides Horizontal Well Program In Wilmington Field

Abstract Computerized mapping, modelling, and simulation programs used in conjunction with advanced geosteering technology have helped to successfully tap bypassed, heavy oil in California's mature Wilmington oil field. While THUMS (Long Beach Company) and Tidelands Oil Production Company-the two field contractors working separate portions of the field operated by the City of Long Beach-have taken different approaches to field optimization using horizontal drilling, each has been rewarded by significant additional production. The following text specifically focusses on how 3D visualization tools have improved Tidelands Oil Production's recovery factor in the "Old Wilmington" or western portion of the field. Data from THUMS' Long Beach Unit, the eastern portion of the field, are included where needed to provide a thorough field overview. The Challenge The Wilmington oil field produces from Pliocene and Miocene clastic slope and basin turbidite sandstones. The individual reservoirs are defined by graded sequences of sandstone that are interlayered with siltstones and shales. The entire sequence is folded and faulted. Even the typically rhythmically deposited sequences have lenticular lobate shapes and are complicated by basal scour, onlapping, and channelling. The result is a sequence of rocks that often appears to be uniform but is not. These complexities also result in permeability variations that reduce the producibility of the sandstones, impact waterflooding, and result in a substantial amount of bypassed oil. Wilmington Field's stratigraphic layers are divided into seven producing zones, 52 subzones, and locally into even finer subzones(1). The finer subdivisions are defined as hydrologic bodies or depositional sequences. Many techniques are applied todefine the thinner sand bodies into unique units, including core description combined with log-rock typing, detailed log correlation, production/injection history matching, bypassed pay saturation analysis on recent pass-through wells and reservoir simulation(2). There is still much to be learned about the intricacies of Wilmington Field's reservoirs, although today's computerized visualization tools coupled with advanced while-drilling measurements have significantly contributed to the collective knowledgebase about this field. Meanwhile, its poorly drained sands remain ideal targets for horizontal drilling. History in the Long Beach Unit The eastern portion of Wilmington Field was originally produced with more than 1,000 wells drilled between 1965 and 1982. Even given the very long completion intervals used and water injection for pressure support, oil remained in pockets of tight, thin sands, as well in areas with poor injection support. Widely ranging permeabilities and faulting caused typically viscous oil (12.5 ° to 16 °API) to be left. behind in 20 to 50 ft. (6 to 15 m) thick sand units. An additional 460 wells were drilled in the Long Beach Unit from 1982 to 1986 using a "sub-zone" approach to improve sweep efficiency and another 160 million barrels (bbl) or 25.4 million cubic meters (m3) were produced. Then, after 1986 bypassed sands were selectively perforated in even finer intervals.

Well-Completion Technique Using Steam for Formations With Unconsolidated Sands

This article is a synopsis of paper SPE 38793, "A Novel, Low-Cost, Well-Completion Technique Using Steam for Formations with Unconsolidated Sands, Wilmington Field, California," by D.K. Davies, SPE, David K. Davies & Assocs. Inc., and J.J. Mondragon, SPE, and P.S. Hara, SPE, Tidelands Oil Production Co., originally presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October.

Analyzing a Multilateral-Well Failure in the East Wilmington Field of California

Summary As the industry pursues optimum cost drilling techniques, more focus is being applied to multilateral (ML) technology. The presently available literature invariably focuses on the cost and efficiency benefits of drilling ML wells. What is missing in the media, however, are the benefits associated with publication of the negative aspects or costly failures of higher-technology, multiple-lateral projects that require a mechanical tieback, cement, or a pressure seal at the junction of the laterals (i.e., Class 3-, 4-, or 5-type wells, respectively). This paper presents a case study of a Class 4 ML well attempted by THUMS Long Beach Co. in the East Wilmington field of California.

Increasing Reserves in a Mature Giant: Wilmington Field, Los Angeles Basin, Part II: Improving Heavy Oil Production Through Advanced Reservoir Characterization and Innovative Thermal Technologies 

Enhanced recovery of low-gravity oil from unconsolidated, high-porosity, high-permeability sands in the supergiant Wilmington field began in the early 1960s. Despite nearly four decades of production, postprimary recoveries have been generally low due to reservoir heterogeneity and operational problems. In particular, steamflooding has yielded poor results because of elevated steam:oil ratios, early steam breakthrough, and consequent premature equipment failure. A multidiscipline effort to address these problems and improve recovery is underway as part of the U.S. Department of Energy Class III (slope and basin clastic reservoir) Oil Recovery Field Demonstration initiative. In the fault block IIA portion of Wilmington field, this effort has focused on several main objectives. Those objectives discussed in this paper include (1) three-dimensional geologic modeling to rigorously define important relationships; (2) rock typing and rock-log modeling to improve reservoir characterization; (3) testing the feasibility of using horizontal wells in steamflood operations at Wilmington; and (4) employing a novel, low-cost completion technique applicable to unconsolidated formations. To date, significant levels of success have been achieved with regard to all these objectives. When complete, the project at Wilmington field should have wide-ranging application to similar reservoirs throughout southern California and elsewhere.

Increasing Reserves in a Mature Giant: Wilmington Field, Los Angeles Basin, Part 1: Reservoir Characterization to Identify Bypassed Oil 

With estimated reserves of over 2.8 billion bbl oil, the supergiant Wilmington field is the largest productive area in the Los Angeles basin, one of the world’s most prolific petroleum provinces. Similar to most other fields in the basin, Wilmington produces from thick sequences of upper Miocene-Pliocene slope and basin-floor turbidites ranging from well indurated to unconsolidated in character. Due to a range of factors, enhanced recovery in these reservoirs has been incomplete or inefficient, with the result that a substantial remaining resource exists. To help devise improved methods for exploiting this resource, the U.S. Department of Energy has included portions of Wilmington field in its Class 3 [slope and basin clastic reservoirs] Oil Recovery Field Demonstration Program. At present, two projects are underway: one aimed at identifying bypassed pay, and the other project aimed at improving tertiary recovery operations. Both projects have employed advanced reservoir characterization techniques and have demonstrated considerable success. Results of this work should have wide application to slope and basin clastic reservoirs elsewhere. Part 1 of the following two-part paper presents a summary of work completed thus far.

Anelasticity and dispersion in dry unconsolidated sands

Laboratory measurements reveal frame modulus dispersion and creeping behavior in room-dry samples of unconsolidated, quartzo-feldspathic Upper Miocene turbidites from the Wilmington Field, CA. A single standard linear solid model predicts both the dispersion and the creep response. Similar behavior is observed in Ottawa sand samples when mixed with wetted Montmorillonite. In this case the magnitude of dispersion and creep increase with increasing clay content. We suggest that the anelastic behavior of the Wilmington sands is due to the presence of micas and a small amount of clay. The transition frequency of 2×10−4Hz (i.e., between high and low frequency behavior) suggests that seismic, sonic, and ultrasonic measurements of rock moduli are quite similar in the absence of fluids. The static frame modulus should be used to model tectonic processes and long term production-related changes in oil-field environments.